10-K 1 h14014e10vk.txt GENESIS ENERGY, L.P. 12/31/2003 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2003 OR | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-12295 GENESIS ENERGY, L.P. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 76-0513049 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 DALLAS, SUITE 2500, HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 860-2500 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ------------------- Common Units American Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No | | Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). | | The aggregate market value of the Common Units held by non-affiliates of the Registrant on June 30, 2003 (the last business day of Registrant's most recently completed second fiscal quarter), was approximately $52,612,500 based on $6.10 per unit, the closing price of the Common Units as reported on the American Stock Exchange on such date. At March 1, 2004, 9,313,811 Common Units were outstanding. ================================================================================ GENESIS ENERGY, L.P. 2003 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS

Page ---- PART I Items 1. Business and Properties............................................................... 3 and 2 Item 3. Legal Proceedings..................................................................... 11 Item 4. Submission of Matters to a Vote of Security Holders................................... 13 PART II Item 5. Market for Registrant's Common Units and Related Unitholder Matters................... 13 Item 6. Selected Financial and Operating Data................................................. 14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 15 Item 7A. Quantitative and Qualitative Disclosures about Market Risks........................... 41 Item 8. Financial Statements and Supplementary Data........................................... 41 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 41 Item 9A. Controls and Procedures............................................................... 41 PART III Item 10. Directors and Executive Officers of Our General Partner............................... 42 Item 11. Executive Compensation................................................................ 44 Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 46 Item 13. Certain Relationships and Related Transactions........................................ 47 Item 14. Principal Accountants Fees and Services............................................... 48 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 48

2 FORWARD-LOOKING INFORMATION The statements in this Annual Report on Form 10-K that are not historical information may be "forward looking statements" within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These statements include, but are not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," or "intend" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. These risks and uncertainties include general economic conditions, market and business conditions, opportunities that may be presented and pursued by us or the lack of such opportunities, competitive actions by other companies in our industries, changes in laws and regulations, access to capital, and other factors. Therefore, all the forward-looking statements made in this document are qualified in their entirety by these cautionary statements, and no assurance can be made that our goals will be achieved or that expectations regarding future developments will prove to be correct. Please read "Other Matters- Risk Factors Related to Our Business" discussed in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. PART I ITEMS 1AND 2. BUSINESS AND PROPERTIES WEBSITE ACCESS TO REPORTS We make available free of charge on our internet website (www.genesiscrudeoil.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 available as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. GENERAL Genesis Energy, L.P., a Delaware limited partnership, was formed in December 1996. We conduct our operations through our affiliated limited partnership, Genesis Crude Oil, L.P. and its subsidiary partnerships (collectively, the "Partnership" or "Genesis"). We are engaged in three operations - crude oil gathering and marketing, crude oil pipeline transportation and carbon dioxide (CO2) marketing. We are an independent gatherer and marketer of crude oil. Our operations are concentrated in Texas, Louisiana, Alabama, Florida, and Mississippi. Our gathering and marketing margins are generated by buying crude oil at competitive prices, efficiently transporting or exchanging the crude oil and marketing the crude oil to customers at favorable prices. We utilize our trucking fleet of 49 leased tractor-trailers and our gathering lines to transport crude oil. We also transport purchased crude oil on trucks, barges and pipelines owned and operated by third parties. Our operations include transportation of crude oil at regulated published tariffs on our three common carrier pipeline systems. These systems are the Texas System, the Jay System extending between Florida and Alabama, and the Mississippi System extending between Mississippi and Louisiana. The Jay and Mississippi pipeline systems have numerous points where the crude oil owned by the shipper can be injected into the pipeline for delivery to or transfer to connecting pipelines. The Texas pipeline system receives all of its volume from connections to other carriers. Genesis earns a tariff for the transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point. In November 2003, we acquired assets enabling us to start a wholesale CO2 operation. We acquired a volumetric production payment from Denbury Resources Inc. that will provide us with 167.5 billion cubic feet (Bcf) 3 of CO2. We also acquired from Denbury three of their long-term industrial supply contracts for CO2. We will ship the CO2 from the source to the customers on a pipeline owned by Denbury and will sell the CO2 to the customers. These sales contracts extend through 2015. Genesis Energy, Inc. (the "General Partner"), a Delaware corporation, serves as the sole general partner of Genesis Energy, L.P., Genesis Crude Oil, L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. The General Partner is owned by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc. Denbury acquired the General Partner from Salomon Smith Barney Holdings Inc. and Salomon Brothers Holding Company Inc. in May 2002. DESCRIPTION OF SEGMENTS AND RELATED ASSETS Crude Oil Gathering and Marketing In our gathering and marketing business, we are principally engaged in the purchase and aggregation of crude oil for resale at various points along the crude oil distribution chain, which extends from the wellhead to aggregation at terminal facilities and refineries. (the "Distribution Chain"). We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transport the crude oil along the Distribution Chain for sale to or exchange with customers. Our margins from our gathering and marketing operations are generated by the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation and the cost of supplying credit. We generally enter into an exchange transaction only when the cost of the exchange is less than the alternative costs that we would otherwise incur in transporting or storing the crude oil. In addition, we may exchange one grade of crude oil for another to maximize margins or meet contractual delivery requirements. Segment margin from our crude oil gathering and marketing operations varies from period to period, depending, to a significant extent, upon changes in the supply of and demand for crude oil and the resulting changes in U.S. crude oil inventory levels. Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. An increase in the market price of crude oil does not impact us to the extent many people expect. When market prices for crude oil increase, we must pay more for crude oil, but we normally are able to sell it for more. To the extent we have crude oil inventories; we can be impacted by market price changes. We also make bulk purchases of crude oil at pipeline and terminal facilities. When opportunities arise to increase margin or to acquire a grade of crude oil that more nearly matches the specifications for crude oil we are obligated to deliver, we may exchange crude oil with third parties through exchange or buy/sell agreements. Both bulk purchases and buy/sell agreements were significantly reduced in 2002 compared to prior years. During 2003, our bulk and exchange transactions averaged 12,000 barrels per day, down from 246,319 barrels per day in the fourth quarter of 2001. The reduction is attributable primarily to credit requirements for these transactions as discussed below. We provide crude oil gathering services through our fleet of 49 leased tractor-trailers. The trucking fleet generally hauls the crude oil to one of the approximately 60 pipeline injection stations owned or leased by us. We may sell the crude oil as it exits our injection station and enters the pipeline, or we may ship the crude oil on the pipeline to a point further along the Distribution Chain. Producer Services Crude oil purchasers who buy from producers compete on the basis of competitive prices and quality of services. Through our team of crude oil purchasing representatives, we maintain relationships with more than 400 producers. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. High-quality field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline 4 deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by the Partnership), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners and calculating and paying production taxes on behalf of interest owners. In order to compete effectively, we must make prompt and correct payment of crude oil production proceeds on a monthly basis, together with the correct payment of all severance and production taxes associated with such proceeds. In 2003, we distributed payments to approximately 17,000 interest owners. Credit Our credit standing is an important consideration for parties with whom we do business. Some counterparties, in connection with our crude oil purchases or exchanges, require us to furnish guarantees or letters of credit. When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. Since typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is an important consideration in our business. We believe that our sales are made to creditworthy entities or entities with adequate credit support. We have not experienced any nonpayment or nonperformance by our customers. Over the last three years there have been an unusual number of business failures and very large restatements by small as well as large companies in the energy industry. Because the energy industry is very credit intensive, these failures and restatements have focused attention on the credit risks of companies in the energy industry by credit rating agencies, producers and counterparties. This focus on credit has affected requests for credit from producers. While we have seen some increase in requests for credit support from producers, we have been relatively successful in obtaining open credit from most producers. When credit support has been required, we have generally been successful in adjusting the price we pay to purchase the crude oil to reflect our cost of providing letters of credit. Credit review and analysis are also integral to our leasehold purchases. Payment for all or substantially all of the monthly leasehold production is sometimes made to the operator of the lease, who is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, we determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend us in the event any third party should bring a protest, action or complaint in connection with the distribution of production proceeds by the operator. Competition In the crude oil gathering and marketing business, there is intense competition for leasehold purchases of crude oil. The number and location of our pipeline systems and trucking facilities give us access to domestic crude oil production throughout our area of operations. We purchase leasehold barrels from more than 400 producers. We have considerable flexibility in marketing the volumes of crude oil that we purchase, without dependence on any single customer or transportation or storage facility. Our largest competitors in the purchase of leasehold crude oil production are Plains Marketing, L.P., Link Energy Partners, L.P., Shell Trading Company, GulfMark Energy, Inc. and TEPPCO Partners, L.P. Additionally, we compete with many regional or local gatherers who may have significant market share in the areas in which they operate. Competitive factors include price, personal relationships, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems. As part of the sale of our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P., we agreed not to compete in a 40 county area for five years from the effective date of the transaction of October 31, 2003. See additional information on this sale below. Crude Oil Pipeline Transportation Through the pipeline systems we own and operate our pipeline subsidiaries transport crude oil for our gathering and marketing operations and other shippers pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") or the Texas Railroad Commission. Accordingly, we offer transportation services to any shipper of crude oil, provided that the products tendered for transportation satisfy the conditions and 5 specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the particular point where the crude oil was injected into the pipeline and the delivery point. We also can earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses from whatever source, we deduct volumetric pipeline loss allowances and crude quality deductions. Such allowances and deductions are offset by measurement gains and losses. When the allowances and deductions exceed measurement losses, the net pipeline loss allowance volumes are earned and recognized as income and inventory available for sale valued at the market price for the crude oil. Until the volumes are sold, they are held as inventory at the lower of cost or market value. When the volumes are sold, any difference between the carrying amount and the sale price is recognized as additional pipeline revenue. The margins from our pipeline operations are generated by the difference between the revenues from regulated published tariffs, pipeline loss allowance revenues and the fixed and variable costs of operating and maintaining our pipelines. We own and operate three common carrier crude oil pipeline systems. The pipelines and related gathering systems consist of the 135-mile Texas system, the 103-mile Jay System, and the 266-mile Mississippi System. In 2003 we sold portions of our Texas system to TEPPCO Crude Pipeline, L.P. and to Blackhawk Pipeline, L.P., an affiliate of MultiFuels, Inc. The segments we sold to TEPPCO included Bryan to Hearne, Conroe to Satsuma, Hillje to West Columbia and Withers to West Columbia. TEPPCO also acquired our crude oil gathering and marketing operations in the 40 county area surrounding the pipeline. The segments we sold to Blackhawk had been idle since 2002. These segments include Neches to Satsuma, Raccoon Bend to Satsuma and a short portion of the segment from Satsuma to Cullen Junction. We abandoned in place segments that had been idled in 2002, primarily between Satsuma and Cullen Junction. The segments we continue to operate extend from West Columbia to Webster, Cullen Junction to Webster, Webster to Texas City and Webster to Houston. These segments include approximately 135 miles of pipe. We entered into a joint tariff with TEPPCO to receive oil from their system at West Columbia and Cullen Junction. We also continue to receive barrels from a connection with Seminole Pipeline Company at Webster. The joint tariff arrangement with TEPPCO ends in September 2004 when we will idle the West Columbia to Webster segment and the Cullen Junction to Webster segment. We will idle these segments to avoid the costs of testing and possible repairs required under pipeline integrity management regulations. See Regulation - Safety Regulations below. We will evaluate alternatives at that time, including converting the segments to natural gas service. We own approximately 500,000 barrels of storage capacity associated with the Texas pipeline system that is temporarily being used in conjunction with our transitional arrangement with TEPPCO. Once TEPPCO integrates the assets they acquired from us into their operations, we will idle all of this storage capacity. Additionally, we lease approximately 200,000 barrels of storage capacity for the Texas System in Webster. The Mississippi system extends from Soso, Mississippi to Liberty, Mississippi and then from Liberty, Mississippi to near Baton Rouge, Louisiana. We own 200,000 barrels of storage capacity on our Mississippi System, with the tankage located at different places along the system. The segment of the Mississippi system from Liberty to Baton Rouge has been temporarily idled since February 2002. In the second quarter of 2004, we will remove the oil from this segment of the pipeline and consider alternatives for its use, including product or natural gas service. The Jay system begins near oil fields in southeastern Alabama and the panhandle of Florida and extends to a point near Mobile, Alabama. The Jay system has 230,000 barrels of storage capacity, primarily at Jay station. Credit Under the tariffs we have filed with the FERC and the Texas Railroad Commission, shippers are required to pay the tariff invoices we send to them within ten days of receipt of the invoices. If they fail to do so, we can charge interest and suspend service to that shipper. Because shippers do not want any disruption in shipments, they generally pay the invoices promptly. Additionally, the larger shippers on our systems are large oil companies. Under the joint tariff with TEPPCO for the Texas system, TEPPCO invoices and collects the tariff from the shipper and remits to us our share of the joint tariff. 6 The only shipper on our Mississippi system as of December 31, 2003 is Genesis Crude Oil, L.P. Genesis buys production from producers, primarily Denbury, and ships it on the pipeline for sale at Liberty to third parties. Competition Our most significant competitors in our pipeline operations are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where the Mississippi and Texas Systems deliver crude oil. The Jay System operates in an area not currently served by pipeline competitors. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to production, refineries and connecting pipelines. We believe that high capital costs, tariff regulation and the cost of acquiring rights-of-way make it unlikely that other competing crude oil pipeline systems, comparable in size and scope to our pipelines, will be built in the same geographic areas in the near future, provided that our pipelines continue to have available capacity to satisfy demands of shippers and that our tariffs remain competitive. CO2 Marketing In November 2003, we entered the wholesale CO2 marketing business. We acquired a volumetric production payment from Denbury consisting of 167.5 Bcf of CO2. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. We also acquired from Denbury three long-term CO2 agreements with industrial customers to supply CO2 through 2015. Denbury transports the CO2 to the customer, charging us a fee. We then sell the CO2 to the customers who treat the CO2 and sell it to end users for use it for beverage carbonation and food chilling and freezing. The margins from the CO2 operations are generated by the difference between the sales price of the CO2 to the industrial customers and the costs of the transportation provided by Denbury. Credit The three customers we have contracts with for CO2 sales are large companies with good credit ratings. We do not expect to experience any credit related issues with these customers, however we do monitor their credit standings on an ongoing basis. Competition Naturally-occurring CO2, like that from the Jackson Dome area, occurs infrequently, and only in limited areas east of the Mississippi River, including the fields controlled by Denbury. This natural CO2 requires less processing and treatment in order to be of a quality to be used in food than does CO2 that is a by-product of fertilizer production. Our industrial CO2 customers have facilities that are connected to Denbury's CO2 pipeline to make delivery easy and efficient. CO2 does have other uses, such as tertiary recovery in oil fields, should the food industries uses decline. Our contracts have take-or-pay provisions requiring minimum volumes each year for each customer that must be paid for even if the CO2 is not taken. EMPLOYEES To carry out various purchasing, gathering, transporting and marketing activities, the General Partner employed, at December 31, 2003, approximately 200 employees, including management, truck drivers and other operating personnel, division order analysts, accountants, tax specialists, contract administrators, schedulers, marketing and credit specialists and employees involved in our pipeline operations. None of the employees are represented by labor unions, and we believe that relationships with our employees are good. REGULATION Sarbanes-Oxley Act of 2002 In July 2002, the Sarbanes-Oxley Act of 2002 was signed into law to protect investors by improving the accuracy and reliability of corporate disclosures made pursuant to securities laws. The Securities and Exchange Commission has issued rules to adopt and implement the Sarbanes-Oxley Act. These rules include certifications by our Chief Executive Officer and Chief Financial Officer in our quarterly and annual filings with the SEC; disclosures regarding controls and procedures, disclosures regarding critical accounting estimates and policies and 7 requirements to make filings with the SEC available on our website. Additional rules include disclosures regarding audit committee financial experts and charters, disclosure of our Code of Ethics for the CEO and senior financial officers, disclosures regarding contractual obligations and off-balance sheet arrangements and transactions, and requirements for filing earnings press releases with the SEC. Additionally, we will be required to include in our Form 10-K for 2004 an internal control report that contains management's assertions regarding the effectiveness of procedures over financial reporting and a report from our auditors attesting to that certification. Our deadlines for filing quarterly and annual filings with the SEC will also be shortened under the regulations. Pipeline Tariff Regulation The interstate common carrier pipeline operations of the Jay and Mississippi systems are subject to rate regulation by FERC under the Interstate Commerce Act ("ICA"). FERC regulations require that oil pipeline rates be posted publicly and that the rates be "just and reasonable" and not unduly discriminatory. Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were "grandfathered", limiting the challenges that could be made to existing tariff rates. Increases from grandfathered rates of interstate oil pipelines are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the year to year change in an index. Under the regulations, we are able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. FERC allows for rate changes under three methods--a cost-of-service methodology, competitive market showings ("Market-Based Rates"), or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). The pipeline tariff rates on our Mississippi and Jay Systems are either rates that were grandfathered and have been changed under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party. Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Texas Railroad Commission. The applicable Texas statutes require that pipeline rates be non-discriminatory and provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. Most of the volume on our Texas system is now shipped under a joint tariff with TEPPCO. Approximately 10% of the volume shipped is pursuant to a tariff we issued. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained. Environmental Regulations We are subject to federal and state laws and regulations relating to the protection of the environment. At the federal level such laws include the Clean Air Act; the Clean Water Act; the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the National Environmental Policy Act. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties or in the imposition of injunctive relief. Although compliance with such laws has not had a significant effect on our business, such compliance in the future could prove to be costly, and there can be no assurance that we will not incur such costs in material amounts. The Clean Air Act regulates, among other things, the emission of volatile organic compounds in order to minimize the creation of ozone. Such emissions may occur from the handling or storage of crude oil. The required levels of emission control are established in state air quality control implementation plans. Both federal and state laws impose substantial penalties for violation of these applicable requirements. We believe that we are in substantial compliance with applicable clean air requirements. The Clean Water Act controls the discharge of oil and derivatives into certain surface waters. The Clean Water Act provides penalties for any discharges of crude oil in harmful quantities and imposes liability for the costs of removing an oil spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of crude oil in surface waters or into the ground. Federal and state permits for water discharges may be required. The Oil Pollution Act of 1990 ("OPA"), as amended by the Coast Guard Authorization Act of 1996, requires operators of offshore facilities and certain onshore facilities near or 8 crossing waterways to provide financial assurance in the amount of $35 million to cover potential environmental cleanup and restoration costs. This amount is subject to upward regulatory adjustment. We believe that we are in substantial compliance with the Clean Water Act and OPA. We have developed an Integrated Contingency Plan (ICP) to satisfy components of the OPA, as amended in the Clean Water Act. The ICP also satisfies regulations of the federal Department of Transportation, the federal Occupational Safety and Health Act ("OSHA") and state regulations. This plan meets regulatory requirements as to notification, procedures, response actions, response teams, response resources and spill impact considerations in the event of an oil spill. The Resource Conservation and Recovery Act regulates, among other things, the generation, transportation, treatment, storage and disposal of hazardous wastes. Transportation of petroleum, petroleum derivatives or other commodities may invoke the requirements of the federal statute, or state counterparts, which impose substantial penalties for violation of applicable standards. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. Such persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the ordinary course of our operations, substances may be generated or handled which fall within the definition of "hazardous substances." Although we have applied operating and disposal practices that were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the property owned or leased by us or under locations where such wastes have been taken for disposal. Further, we may own or operate properties that in the past were operated by third parties whose operations were not under our control. Those properties and any wastes that may have been disposed of or released on them may be subject to CERCLA, RCRA and analogous state laws, and we potentially could be required to remediate such properties. Under the National Environmental Policy Act ("NEPA"), a federal agency, in conjunction with a permit holder, may be required to prepare an environmental assessment or a detailed environmental impact study before issuing a permit for a pipeline extension or addition that would significantly affect the quality of the environment. Should an environmental impact study or assessment be required for any proposed pipeline extensions or additions, the effect of NEPA may be to delay or prevent construction or to alter the proposed location, design or method of construction. We are subject to similar state and local environmental laws and regulations that may also address additional environmental considerations of particular concern to a state. On December 20, 1999, we had a spill of crude oil from our Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek and river nearby. The spill was cleaned up, with ongoing monitoring and reduced clean-up activity expected to continue for an undetermined period of time. The oil spill is covered by insurance and the financial impact to us for the cost of the clean-up has not been material. During 2002, we reached agreement in principal with the US Environmental Protection Agency (EPA) and the Mississippi Department of Environmental Quality (MDEQ) for the payment of fines under federal and state environmental laws with respect to this 1999 spill. Based on the discussions leading to this agreement in principal, we have recorded accrued liabilities totaling $3.0 million during 2001 and 2002. We expect to finalize the agreements with the federal and Mississippi governments during 2004; however, no assurance can be made that we will reach final agreement with the governments or the specific terms of a final agreement if one is reached. Safety and Security Regulations Our crude oil pipelines are subject to construction, installation, operating and safety regulation by the Department of Transportation ("DOT") and various other federal, state and local agencies. The Pipeline Safety Act 9 of 1992, among other things, amends the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA") in several important respects. It requires the Research and Special Programs Administration ("RSPA") of DOT to consider environmental impacts, as well as its traditional public safety mandates, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and other records to RSPA. It also authorizes RSPA to require that pipelines be modified to accommodate internal inspection devices, to mandate the installation of emergency flow restricting devices for pipelines in populated or sensitive areas, and to order other changes to the operation and maintenance of petroleum pipelines. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. On March 31, 2001, the Department of Transportation promulgated Integrity Management Plan (IMP) regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect a High Consequence Area. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. A High Consequence Area (HCA) is defined as (a) a commercially navigable waterway; (b) an urbanized area that contains 50,000 or more people and has a density of at least 1,000 people per square mile; (c) other populated areas that contain a concentrated population, such as an incorporated or unincorporated city, town or village; and (d) an area of the environment that has been designated as unusually sensitive to oil spills. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. The IMP regulation required us to prepare an Integrity Management Plan that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The risk factors to be considered include proximity to population areas, waterways and sensitive areas, known pipe and coating conditions, leak history, pipe material and manufacturer, adequacy of cathodic protection, operating pressure levels and external damage potential. The IMP regulations require that the baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. As testing is complete, we are required to take prompt remedial action to address all integrity issues raised by the assessment. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to Genesis that may not be fully recoverable by tariff increases. We have developed a Risk Management Plan as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas (USAs) along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential of a spill of crude oil on waterways. States are largely preempted from regulating pipeline safety by federal law but may assume responsibility for enforcing federal pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. Our crude oil pipelines are also subject to the requirements of the Office of Pipeline Safety of the federal Department of Transportation regulations requiring qualification of all pipeline personnel. The Operator Qualification (OQ) program required operators to develop and submit a written program. The regulations also required all pipeline operators to develop a training program for pipeline personnel and qualify them on individually covered tasks at the operator's pipeline facilities. The intent of the OQ regulations is to ensure a qualified workforce by pipeline operators and contractors when performing covered tasks on the pipeline and its facilities, thereby reducing the probability and consequences of incidents caused by human error. Our crude oil operations are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. We believe that our crude oil pipelines and trucking operations have been operated in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Various other federal and state regulations require that we train all employees in pipeline and trucking operations in HAZCOM and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request. 10 In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards such as those described above. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will spend a total of approximately $2.2 million in 2004 and 2005 for testing and rehabilitation under the IMP. We operate our fleet of leased trucks as a private carrier. Although a private carrier that transports property in interstate commerce is not required to obtain operating authority from the ICC, the carrier is subject to certain motor carrier safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations. We are subject to federal EPA regulations for the development of written Spill Prevention Control and Countermeasure (SPCC) Plans. All trucking facilities have a current SPCC Plan and employees have received training on the SPCC Plans and regulations. Annually, trucking employees receive training regarding the transportation of hazardous materials. Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration (an agency of the Department of Homeland Security, which has assumed responsibility from the DOT). None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack. Commodities regulation If we use futures and options contracts that are traded on the NYMEX, these contracts are subject to strict regulation by the Commodity Futures Trading Commission and the rules of the NYMEX. SUMMARY OF TAX CONSIDERATIONS The tax consequences of ownership of common units depend on the owner's individual tax circumstances. However, the following is a brief summary of material tax consequences of owning and disposing of common units. Partnership Status; Cash Distributions We are classified for federal income tax purposes as a partnership based upon our meeting certain requirements imposed by the Internal Revenue Code (the "Code"), which we must meet every year. The owners of common units are considered partners in the Partnership so long as they do not loan their common units to others to cover short sales or otherwise dispose of those units. Accordingly, we pay no federal income taxes, and each common unitholder is required to report on the unitholders federal income tax return the unitholder's share of our income, gains, losses and deductions. In general, cash distributions to a common unitholder are taxable only if, and the extent that, they exceed the tax basis in the common units held. Partnership Allocations In general, our income and loss is allocated to the general partner and the unitholders for each taxable year in accordance with their respective percentage interests in the Partnership (including, with respect to the general partner, its incentive distribution right), as determined annually and prorated on a monthly basis and subsequently apportioned among the general partner and the unitholders of record as of the opening of the first business day of the month to which they related, even though unitholders may dispose of their units during the month in question. A unitholder is required to take into account, in determining federal income tax liability, the unitholder's share of income generated by us for each taxable year of the Partnership ending within or with the unitholder's taxable year, even if cash distributions are not made to the unitholder. As a consequence, a unitholder's share of our taxable income (and possibly the income tax payable by the unitholder with respect to such income) may exceed the cash actually distributed to the unitholder by us. At any time incentive distributions are made to the general partner, gross income will be allocated to the recipient to the extent of those distributions. Basis of Common Units A unitholder's initial tax basis for a common unit is generally the amount paid for the common unit. A unitholder's basis is generally increased by the unitholder's share of our income and decreased, but not below zero, by the unitholder's share of our losses and distributions. 11 Limitations on Deductibility of Partnership Losses In the case of taxpayers subject to the passive loss rules (generally, individuals and closely-held corporations), any partnership losses are only available to offset future income generated by us and cannot be used to offset income from other activities, including passive activities or investments. Any losses unused by virtue of the passive loss rules may be fully deducted if the unitholder disposes of all of the unitholder's common units in a taxable transaction with an unrelated party. Section 754 Election We have made the election pursuant to Section 754 of the Code, which will generally result in a unitholder being allocated income and deductions calculated by reference to the portion of the unitholder's purchase price attributable to each asset of the Partnership. Disposition of Common Units A unitholder who sells common units will recognize gain or loss equal to the difference between the amount realized and the adjusted tax basis of those common units. A unitholder may not be able to trace basis to particular common units for this purpose. Thus, distributions of cash from us to a unitholder in excess of the income allocated to the unitholder will, in effect, become taxable income if the unitholder sells the common units at a price greater than the unitholder's adjusted tax basis even if the price is less than the unitholder's original cost. Moreover, a portion of the amount realized (whether or not representing gain) will be ordinary income. State, Local and Other Tax Considerations In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which a unitholder resides or in which we do business or own property. A unitholder may be required to file state income tax returns and to pay taxes in various states. A unitholder may be subject to penalties for failure to comply with such requirement. In certain states, tax losses may not produce a tax benefit in the year incurred (if, for example, we have no income from sources within that state) and also may not be available to offset income in subsequent taxable years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be more or less than a particular unitholder's income tax liability owed to the state, may not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. It is the responsibility of each prospective unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of the unitholder's investment in us. Further, it is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of the unitholder. Ownership of Common Units by Tax-Exempt Organizations and Certain Other Investors An investment in common units by tax-exempt organizations (including IRAs and other retirement plans), regulated investment companies (mutual funds) and foreign persons raises issues unique to such persons. Virtually all income allocated to a unitholder that is a tax-exempt organization is unrelated business taxable income and, thus, is taxable to such a unitholder. Furthermore, no significant amount of our gross income is qualifying income for purposes of determining whether a unitholder will qualify as a regulated investment company, and a unitholder who is a nonresident alien, foreign corporation or other foreign person is regarded as being engaged in a trade or business in the United States as a result of ownership of a common unit and, thus, is required to file federal income tax returns and to pay tax on the unitholder's share of our taxable income. Finally, distributions to foreign unitholders are subject to federal income tax withholding. Tax Shelter Registration The Code generally requires that "tax shelters" be registered with the Secretary of the Treasury. We are registered as a tax shelter with the Secretary of the Treasury. Our tax shelter registration number is 97043000153. Issuance of the registration number does not indicate that an investment in the Partnership or the claimed tax benefits has been reviewed, examined or approved by the Internal Revenue Service. 12 ITEM 3. LEGAL PROCEEDINGS We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on the financial condition or results of our operations. For information on the settlement of litigation with Pennzoil see Management's Discussion and Analysis - Other Matters on page 39. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the security holders during the fiscal year covered by this report. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS The Common Units are listed on the American Stock Exchange under the symbol "GEL". The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit and the amount of cash distributions paid per Common Unit.

Price Range --------------------- Cash High Low Distributions(1) ------- ------- ---------------- 2002 First Quarter...................................... $ 3.94 $ 2.31 $ -- Second Quarter..................................... $ 4.20 $ 1.80 $ -- Third Quarter...................................... $ 5.75 $ 2.00 $ -- Fourth Quarter..................................... $ 5.00 $ 4.05 $ 0.20(2) 2003 First Quarter...................................... $ 5.70 $ 4.11 $ -- Second Quarter..................................... $ 6.59 $ 4.62 $ 0.05 Third Quarter...................................... $ 7.60 $ 5.10 $ 0.05 Fourth Quarter..................................... $ 10.00 $ 6.85 $ 0.05

---------- (1) Cash distributions are shown in the quarter paid and are based on the prior quarter's activities. (2) A special distribution of $0.20 per unit was paid on December 16, 2002 to mitigate potential taxable income allocations to Unitholders. At December 31, 2003, there were 9,313,811 Common Units outstanding, including 688,811 Common Units held by our General Partner. As of December 31, 2003, there were approximately 6,500 record holders and beneficial owners (held in street name) of our Common Units. We distribute all of our Available Cash as defined in the Partnership Agreement within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves. Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which is filed as an exhibit to this Form 10-K. Our target minimum quarterly distribution is $0.20 per Common Unit. In addition to its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. In 2001, we announced that we would not pay a distribution for the fourth quarter of 2001, which would normally have been paid in February 2002. We did not pay regular distributions for 2002. We paid a special distribution in the fourth quarter of 2002 to mitigate potential taxable income allocations to unitholders. In 2003, we began paying quarterly distributions again with distributions for the first quarter of 2003 of $0.05 per unit. For the fourth quarter of 2003, we increased our distribution to $0.15 per unit (which was paid in February 2004). 13 ITEM 6. SELECTED FINANCIAL DATA The table below includes selected financial data for the Partnership for the years ended December 31, 2003, 2002, 2001, 2000, and 1999 (in thousands, except per unit and volume data).

Year Ended December 31, ---------------------------------------------------------------------------- 2003 2002 2001 2000 1999 ---------- ------------ ---------- ---------- ---------- INCOME STATEMENT DATA: Revenues: Crude oil revenues: Gathering & marketing ...................... $ 641,684 $ 639,143(1) $3,001,632 $3,897,799 $1,941,353 Pipeline ................................... 15,134 13,485 9,948 10,728 12,344 CO2 revenues ................................... 1,079 -- -- -- -- Total revenues ............................. 657,897 652,628 3,011,580 3,908,527 1,953,697 Costs and expenses: Crude oil costs: Crude oil and field operating .............. 633,776 627,966(1) 2,991,904 3,887,474 1,927,930 Pipeline operating ......................... 10,324 8,076 7,038 5,342 5,067 CO2 transportation costs ....................... 355 -- -- -- -- ---------- ------------ ---------- ---------- ---------- General and administrative expenses ............ 8,768 7,864 11,307 10,623 11,358 Depreciation and amortization .................. 4,641 4,603 5,340 6,023 6,250 Impairment of long-lived assets ................ -- -- 9,589(2) -- -- Change in fair value of derivatives .................................... -- 1,279 (1,681) -- -- Gain from sale of surplus assets ............... (236) (705) (167) (1,148) (849) Other operating charges ........................ -- 1,500 1,500 1,387 -- ---------- ------------ ---------- ---------- ---------- Total costs and expenses ................... 657,330 650,583 3,024,830 3,909,701 1,949,756 ---------- ------------ ---------- ---------- ---------- Operating income (loss) from continuing operations ................................... 34 2,045 (13,250) (1,174) 3,941 Interest expense, net ............................. (986) (1,035) (527) (1,010) (929) Minority interests effects ........................ -- -- 1 223 (602) ---------- ------------ ---------- ---------- ---------- Income (loss) in continuing operations before cumulative effect of change in accounting principle ...................... (717) 1,010 (13,776) (1,961) 2,410 Income (loss) from discontinued operations ................................... 14,039 4,082 (30,303)(2) 2,142 (78) Cumulative effect of change in accounting principle, net of minority interest effect ..................... -- -- 467 -- -- ---------- ------------ ---------- ---------- ---------- Net income (loss) ................................. $ 13,322 $ 5,092 $ (43,612) $ 181 $ 2,332 ========== ========== ========== ========== ========== Net income (loss) per common unit-basic and diluted: Continuing operations .......................... $ (0.05) $ 0.12 $ (1.57) $ (0.22) $ 0.35 Discontinued operations ........................ 1.55 0.46 (3.44) 0.24 (0.08) Cumulative effect of change in accounting principle ......................... -- -- 0.05 -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) .............................. $ 1.50 $ 0.58 $ (4.96) $ 0.02 $ 0.27 ========== ========== ========== ========== ========== Cash distributions per common unit: ............... $ 0.15 $ 0.20 $ 0.80 $ 2.28 $ 2.00

14

Year Ended December 31, ----------------------------------------------------------------------- 2003 2002 2001 2000 1999 -------- -------- -------- -------- -------- BALANCE SHEET DATA (AT END OF PERIOD): Current assets .................................. $ 88,211 $ 92,830 $182,100 $350,604 $274,717 Total assets .................................... 147,115 137,537 230,113 449,343 380,592 Long-term liabilities ........................... 7,000 5,500 13,900 -- 3,900 Minority interests .............................. 517 515 515 520 30,571 Partners' capital ............................... 52,354 35,302 32,009 82,615 53,585 OTHER DATA: Maintenance capital expenditures(3) ............. $ 4,178 $ 4,211 $ 1,882 $ 1,685 $ 1,682 Volumes-continuing operations: Crude oil gathering and marketing: Wellhead (bpd) ............................. 45,015 47,819 67,373 94,995 89,076 Bulk and exchange (bpd) .................... 11,790 25,610(1) 253,159 264,235 215,019 Crude oil pipeline (bpd) ..................... 66,959 71,870 80,408 82,092 89,298 CO2 marketing(4) (Mcf) ....................... 36,332 -- -- -- --

(1) At the end of 2001, we changed our business model to substantially eliminate bulk and exchange transactions due to relatively low margins and high credit requirements. (2) In 2001, we recorded an impairment charge of $45.1 million, with $35.5 million of that amount included in discontinued operations. This impairment charge related to goodwill and our pipeline operations. (3) Maintenance capital expenditures are capital expenditures to replace or enhance partially or fully depreciated assets to sustain the existing operating capacity or efficiency of our assets and extend their useful lives. (4) Represents average daily volume for the two month period that we owned the assets. The table below summarizes our quarterly financial data for 2003 and 2002 (in thousands, except per unit data).

2003 Quarters -------------------------------------------------------------- First Second Third Fourth --------- --------- --------- --------- Revenues - continuing operations ............................ $ 175,682 $ 146,670 $ 157,094 $ 178,451 Operating income (loss) - continuing operations ............. $ 923 $ 903 $ (1,411) $ (145) Income (loss) from continuing operations .................... 381 745 (1,568) (275) Income from discontinued operations ......................... 489 1,145 355 12,041 Net income (loss) ........................................... $ 879 $ 1,890 $ (1,213) $ 11,766 Net income (loss) per Common Unit- basic and diluted ...................................... $ 0.10 $ 0.21 $ (0.14) $ 1.28

2002 Quarters -------------------------------------------------------------- First Second Third Fourth --------- --------- --------- --------- Revenues - continuing operations ............................ $ 176,757 $ 169,681 $ 154,357 $ 147,961 Operating income (loss) - continuing operations ............. $ (239) $ 941 $ 604 $ 1,268 Income (loss) from continuing operations .................... (725) 569 34 1,087 Income (loss) from discontinued operations .................. 2,039 1,537 69 482 Net income (loss) ........................................... $ 1,314 $ 2,106 $ 103 $ 1,569 Net income (loss) per Common Unit - basic and diluted ...................................... $ 0.15 $ 0.24 $ 0.01 $ 0.18

15 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Included in Management's Discussion and Analysis are the following sections: - Overview of 2003 - Critical Accounting Policies - Results of Operations and Outlook for 2004 and Beyond - Liquidity and Capital Resources - Commitments and Off-Balance Sheet Arrangements - Other Matters - New Accounting Pronouncements In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and available cash. Our profitability depends to a significant extent upon our ability to maximize segment margin. Segment margin is calculated as revenues less cost of sales and operating expense, and does not include depreciation and amortization. A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 8 to the consolidated financial statements. Available Cash is a non-GAAP liquidity measure calculated as net income with several adjustments, the most significant of which are the elimination of gains and losses on asset sales, except those from the sale of surplus assets, the addition of non-cash expenses such as depreciation, and the subtraction of maintenance capital expenditures, which are expenditures to sustain existing cash flows but not to provide new sources of revenues. For additional information on Available Cash and a reconciliation of this measure to cash flows from operations, see "Non-GAAP Financial Measure" below. OVERVIEW OF 2003 Genesis Energy, L.P. is a Delaware limited partnership that is publicly traded on the American Stock Exchange. We operate through Genesis Crude Oil, L.P., and its subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline, USA, L.P. Our operations are managed through our general partner, Genesis Energy, Inc., a wholly-owned indirect subsidiary of Denbury Resources Inc. The general partner holds a 2% general partner interest and a 7.25% limited partner interest and public unitholders hold an aggregate 90.75% limited partner interest in Genesis Energy, L.P. We operate in three business segments - crude oil gathering and marketing, crude oil pipeline transportation and CO2 marketing. Our revenues are earned by selling crude oil and CO2 and by charging fees for the transportation of crude oil on our pipelines. Our focus is on the margin we earn on these revenues, which is calculated by subtracting the costs of the crude oil, the costs of transporting the crude oil and CO2 to the customer, and the costs of operating our assets. Our primary goal is to generate Available Cash for our unitholders. This Available Cash is then distributed quarterly to our unitholders. We are pleased with the progress we made in 2003 toward our goal of generating more stable sources of Available Cash. Two significant actions that we took in 2003 toward this goal were: - Disposing of our Texas Gulf Coast operations - Purchasing a CO2 volumetric production payment and related marketing contracts. During the fourth quarter of 2003, we closed the sale of portions of our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P. We also sold portions of our Texas pipeline system that we idled in 2002 to Blackhawk Pipeline, L.P. We abandoned in place other portions of the Texas pipeline system. The sale of these operations was the result of an initiative we started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs or risks of operation, and which segments we should invest in for future growth. As a result of these actions we recorded a gain on the disposal of these discontinued operations of $13.0 million. The sale of the Texas Gulf Coast operations to TEPPCO benefited both parties almost immediately. TEPPCO realized benefits from integrating these assets into their existing South Texas pipeline system. By selling 16 these assets, we reduced 2004 projected maintenance expenditures by $6.6 million and eliminated potential risks to the continuation of our revenue stream that may have resulted from consolidation of pipeline assets in the area. We believe that these assets had more long-term strategic benefit to TEPPCO than to us. The pipeline segments sold to Blackhawk were assets that we idled in 2002 due to declining volumes and/or risks of operation. We received no proceeds from this sale. By making the sale to Blackhawk, we eliminated costs of maintaining the assets. Blackhawk intends to convert the pipeline segments to natural gas service. The segments we abandoned in place had not been in service since 2002 and this abandonment reduces our costs for monitoring and maintenance. Additionally, this abandonment helped to offset tax gains allocated to our unitholders from the sale to TEPPCO. The carbon dioxide (CO2) volumetric production payment we purchased enables us to commence a wholesale CO2 marketing operation. We acquired this production payment, as well as related long-term CO2 industrial sales contracts, from Denbury. While this CO2 operation will have some seasonality, the cash flows from this operation will be much less volatile than those of our existing crude oil gathering and marketing operation. The funds to acquire this production payment came from the $21 million received from TEPPCO for the sale of the Texas Gulf Coast operations and the issuance of 688,811 limited partner units to our general partner in exchange for $5.0 million. Our continuing operations did not perform as well as expected. Volatility in P-Plus market prices for crude oil has historically created fluctuations in our segment margins. During 2003, we experienced positive results when P-Plus market prices increased in the early part of the year; however, a precipitous decline in segment margin during the latter half of the year offset some of the segment margin earned in the first half of the year. Revenues from our pipeline transportation operations increased primarily due to tariff increases in 2002 and 2003. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from those estimates. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (see Note 2. Summary of Significant Accounting Policies). Critical accounting policies and estimates are those that are most important to the portrayal of our financial results and positions. These policies require management's judgment and often employ the use of information that is inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, pipeline loss allowance recognition, depreciation, amortization and impairment of long-lived assets and contingent and environmental liabilities. These policies are discussed below. Revenue and Expense Accruals Information needed to record our revenues is generally available to allow us to record substantially all of our revenue-generating transactions based on actual information. The accruals that we are required to make for revenues are generally insignificant. We routinely make accruals for expenses due to the timing of receiving third party information and reconciling that information to our records. These accruals can include some crude oil purchase costs and expenses for operating our assets such as contractor charges for goods and services provided. For crude oil purchases transported on our trucks or our pipelines, we have access to the volumetric and pricing data so that we can record these transactions based on actual information. Accounting for crude oil purchases that involve third party transportation services sometimes require us to make estimates, as the necessary volumetric data is not available within the timeframe needed. By balancing our crude oil purchase and sales volumes with the change in our inventory positions, we believe we can make reasonable estimates of the unavailable data. 17 The provisions of SFAS No. 133, as amended, require that estimates be made of the effectiveness of derivatives as hedges and the fair value of derivatives. The actual results of the transactions involving the derivative instruments will most likely differ from the estimates. We make very limited use of derivative instruments; however, when we do, we base these estimates on information obtained from third parties and from our own internal records. We believe our estimates for revenue and expense items are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts. Pipeline Loss Allowance Recognition Numerous factors can cause crude oil volumes to expand and contract. These factors include temperature of both the crude oil and the surrounding atmosphere and the quality of the crude oil, in addition to inherent imprecision of measurement equipment. As a result of these factors, crude oil volumes fluctuate, which can result in losses in volumes of crude oil in the custody of the pipeline that belongs to the shippers. In order to compensate the pipeline for bearing the risk of actual losses in volumes that occur, the pipeline generally has established in its tariffs the right to make volumetric deductions from the shippers for quality and volumetric fluctuations. These deductions are referred to as pipeline loss allowances. These allowances are compared to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or expense, based on prevailing market prices at that time. When net gains occur, the pipeline company has crude oil inventory. When net losses occur, any recorded inventory on hand is reduced and the pipeline records a liability for the purchase of crude oil that it must make to replace the lost volumes. Inventories are reflected in the financial statements at the lower of the recorded value or the market value at the balance sheet date. Liabilities to replace crude oil are valued at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value. Future pipeline loss allowance revenue cannot be predicted, as it depends on factors beyond management's control such as the crude oil quality and temperatures, as well as crude oil market prices. Depreciation, Amortization and Impairment of Long-Lived Assets In order to calculate depreciation and amortization we must estimate the useful lives of our fixed assets at the time the assets are placed in service. Calculation of the useful life of an asset is based on our experience with similar assets. Experience, however, can cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. When events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, we review our assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We compare the carrying value of the fixed asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. Should the undiscounted future cash flows be less than the carrying value, we record an impairment charge to reflect the asset at fair value. Liability and Contingency Accruals We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, accruals are made. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. These estimates are revised as additional information is obtained or resolution is achieved. In 2001, we recorded an estimate of $1.5 million for the potential liability for fines related to the crude oil spill in December 1999 from our Mississippi pipeline system. After assessing information obtained in meetings with the government, this estimate was increased to a total of $3.0 million in 2002. We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. These estimates are sometimes made with the assistance of third parties involved in monitoring the remediation effort. 18 We have recorded an estimate for the additional costs expected to be incurred to complete the remediation of the site of the Mississippi crude oil pipeline spill. This estimate is based upon expectations of the additional work to be performed to meet regulatory requirements and restore the site. Because the costs of remediation and restoration for this spill are covered by insurance, we record a receivable from the insurers for a similar amount. We believe our estimates for contingent liabilities are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts. RESULTS OF OPERATIONS AND OUTLOOK FOR 2004 AND BEYOND The following table summarizes financial data by segment for the years ended December 31, 2003, 2002 and 2001 (in thousands).

Years Ended December 31, ------------------------------------------------- 2003 2002 2001 ----------- ----------- ----------- Revenues Crude oil gathering & marketing ........................... $ 641,684 $ 639,143 $ 3,001,632 Crude oil pipeline ........................................ 15,134 13,485 9,948 CO2 marketing ............................................. 1,079 -- -- ----------- ----------- ----------- Total revenues ................................................ $ 657,897 $ 652,628 $ 3,011,580 =========== =========== =========== Segment margin Crude oil gathering & marketing ........................... $ 7,908 $ 11,177 $ 9,728 Crude oil pipeline ........................................ 5,108 5,409 2,910 CO2 marketing ............................................. 724 -- -- ----------- ----------- ----------- Total segment margin .......................................... $ 13,740 $ 16,586 $ 12,638 General and administrative expenses ........................... 8,768 7,864 11,307 Depreciation and amortization ................................. 4,641 4,603 5,340 Impairment of long-lived assets ............................... -- -- 9,589 Change in fair value of derivatives ........................... -- 1,279 (1,681) Net gain on disposal of surplus assets ........................ (236) (705) (167) Other operating charges ....................................... -- 1,500 1,500 ----------- ----------- ----------- Operating income (loss) ....................................... 567 2,045 (13,250) Interest income (expense), net ................................ (986) (1,035) (527) Minority interest ............................................. -- -- 1 ----------- ----------- ----------- Income from continuing operations ............................. (419) 1,010 (13,776) Discontinued operations, net of minority interest ............. 13,741 4,082 (30,303) Cumulative effect of adoption of FAS 133 ...................... -- -- 467 ----------- ----------- ----------- Net income (loss) ............................................. $ 13,322 $ 5,092 $ (43,612) =========== =========== =========== Barrels per day from continuing operations: Crude oil wellhead ........................................ 45,015 47,819 67,373 Crude oil total ........................................... 56,805 73,429 320,532 Crude oil pipeline ........................................ 66,959 71,870 80,408

CRUDE OIL GATHERING AND MARKETING OPERATIONS The key drivers affecting our crude oil gathering and marketing segment margin include production volumes, volatility of P-Plus, volatility of grade differentials, inventory management, and credit costs. Segment margins from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels for crude oil do not necessarily bear a relationship to segment margin as absolute price levels normally impact revenues and cost of sales by equivalent amounts. Because period-to-period variations in revenues and cost of sales are not generally 19 meaningful in analyzing the variation in segment margin for gathering and marketing operations, such changes are not addressed in the following discussion. In our gathering and marketing business, we seek to purchase and sell crude oil at points along the Distribution Chain where we can achieve positive margins. We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts. We then transport the crude along the Distribution Chain for sale to or exchange with customers. Additionally, we enter into exchange transactions with third parties, generally only when the cost of the exchange is less than the alternate cost we would incur in transporting or storing the crude oil. In addition, we often exchange one grade of crude oil for another to maximize margins or meet contract delivery requirements. Prior to the first quarter of 2002, we purchased crude oil in bulk at major pipeline terminal points. These bulk and exchange transactions were characterized by large volumes and narrow profit margins on purchases and sales. Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. A significant factor affecting our gathering and marketing segment margins is the change in domestic production of crude oil. Short-term and long-term price trends impact the amount of capital that oil producers have available to maintain existing production and to invest in developing crude reserves, which in turn impacts the amount of crude oil that is available to be gathered and marketed by us and our competitors. During the last two years, posted prices for West Texas Intermediate crude oil have ranged from a low near $16 per barrel to a high of $32 per barrel. The volatility in prices over the last two years makes it very difficult to estimate the volume of crude oil available to purchase. We expect to continue to be subject to volatility and long-term declines in the availability of crude oil production for purchase. Crude oil prices in the United States are impacted by both international factors as well as domestic factors. International factors such as wars and conflicts, instability of foreign governments, and labor strikes affect prices, as do the influences in the U.S. of environmental regulations and the supply of domestic production. An increase in the market price of crude oil does not impact us to the extent many people expect. When market prices for oil increase, we must pay more for crude oil, but we normally are able to sell it for more. Most of our contracts for the purchase and sale of crude oil have components in the pricing provisions such that the price paid or received is adjusted for changes in the market price for crude oil. Often the pricing in a contract to purchase crude oil will consist of the market price component and a bonus, which is generally a fixed amount ranging from a few cents to several dollars. Typically the pricing in a contract to sell crude oil will consist of the market price component and a bonus that is not fixed, but instead is based on another market factor. This floating bonus is usually the price quoted by Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed and P-Plus floats in the sales contracts, the margin on individual transactions can vary from month-to-month depending on changes in the P-Plus component. P-Plus does not necessarily move in correlation with the price of crude oil in the market. P-Plus is affected by numerous factors such as future expectations for changes in crude oil prices, such that crude oil prices can be rising, but P-Plus can be decreasing. The table below shows the average P-Plus and the average posted price for West Texas Intermediate (WTI) as posted by Koch Supply & Trading, L.P. by quarter in 2003, 2002 and 2001, based on the simple averaging of the monthly averages. 20

Quarter P-Plus WTI Posting ------- ------ ----------- 2001 First $3.9053 $25.7808 Second $2.7097 $24.8163 Third $3.4173 $23.6087 Fourth $2.8517 $17.2577 2002 First $2.7953 $18.4846 Second $3.3015 $23.0634 Third $3.4400 $25.0589 Fourth $3.5060 $24.9902 2003 First $4.1336 $30.6306 Second $4.6063 $25.7125 Third $4.0336 $27.0065 Fourth $3.4881 $27.9642

As can be seen from this table, changes in P-Plus do not necessarily correspond to changes in the market price of oil. An example is the decline in P-Plus between the third and fourth quarters of 2003 when the WTI posting increased. This unpredictable volatility in P-Plus can create volatility in our earnings. A few purchase contracts and some sale contracts also include a component for grade differentials. The grade refers to the type of crude oil. Crude oils from different wells and areas can have different chemical compositions. These different grades of crude oil will appeal to different customers depending on the processing capabilities of the refineries that ultimately process the crude oil. We may buy crude oil under a contract where we considered the typical grade differences in the market when we set the fixed bonus. If we then sell the oil under a contract with a floating grade differential in the formula, and that grade differential fluctuates, then we can experience an increase or decrease in our margin from that oil purchase and sale. The table below shows the grade differential between West Texas Intermediate grade crude oil and West Texas Sour grade crude oil, using the monthly averages for each quarter of 2001, 2002 and 2003, and the differential between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for the same periods.

WTI/WTS WTI/LLS Quarter Differential Differential ------- ------------ ------------ 2001 First $(3.694) $(0.137) Second $(3.810) $(0.149) Third $(2.047) $(0.081) Fourth $(2.088) $ 0.180 2002 First $(1.536) $ 0.348 Second $(1.218) $ 0.090 Third $(1.028) $(0.323) Fourth $(1.772) $ 0.004 2003 First $(2.361) $ 0.460 Second $(3.189) $(0.216) Third $(2.443) $(0.234) Fourth $(2.711) $ 0.320

As can be seen from this table, the WTI/WTS market differential varied from $1.028 per barrel in the third quarter of 2002 to $3.810 per barrel in second quarter of 2001. The WTI/LLS market differential varied from a negative $0.323 per barrel in the third quarter of 2002 to a positive $0.460 in the first quarter of 2003. This volatility in grade differentials can affect the volatility of our gathering and marketing segment margin. 21 Our purchase and sales contracts are primarily "Evergreen" contracts, which means they continue from month to month unless one of the parties to the contract gives 30-days notice of cancellation. In order to change the pricing in a fixed bonus contract, we would have to give 30-days notice that we want to cancel or renegotiate the contract. This notice time requirement, therefore, means that at least a month will pass before the fixed bonus can be reduced to correspond with a decrease in the P-Plus component of the related sales contract. In this case, our margin would be reduced until such a change is made. Because of the volatility of P-Plus, it is not practical to renegotiate every purchase contract for every change in P-Plus. So segment margins from the sale of the crude oil may be volatile as a result of these timing differences. Another factor that can contribute to volatility in our earnings is inventory management. Generally contracts for the purchase of crude oil will state that we will buy all of the production for the month from a particular well. We generally aggregate the volumes purchased from numerous wells and deliver it into a pipeline where we sell the crude oil to a third party. While oil producers can make estimates of the volume of oil that their wells will produce in a month, they cannot state absolutely how much oil will be produced. Our sales contracts typically state a specific volume to be sold. Consequently, if a well produces more than expected, we will purchase volumes in a month that we have not contracted to sell. These volumes are then held as inventory and are sold in a later month. Should the market price of crude oil fluctuate while we have these inventory volumes, we may have to recognize a loss in our financial statements should the market price fall below the cost of the inventory. Should market prices rise, then we will realize a gain when we sell the unexpected volume of inventory in a later month at higher prices. We make every effort to limit our exposure to these price fluctuations by minimizing inventory volumes. Year Ended December 31, 2003 as Compared to Year Ended December 31, 2002 Gathering and marketing segment margins decreased $3.3 million or 29% to $7.9 million for the year ended December 31, 2003, as compared to $11.2 million for the year ended December 31, 2002. A 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $5.3 million decrease in segment margin, was the primary reason for this decrease. Factors offsetting this decrease were: - A $1.6 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and - a $0.4 million decrease in field operating costs, primarily from a $0.5 million decrease in payroll and benefits, offset by a $0.1 million increase in repair costs. The decreased payroll-related costs can be attributed to an approximate 6 percent decrease in the wellhead volumes. The increase in repair costs is attributable primarily to repairs at truck unloading stations. Although P-Plus declined significantly in the latter half of 2003, the average for 2003 of $4.065 per barrel was 25% higher than the average for 2002 of $3.261 per barrel. This price increase was not enough however to offset the decline in volumes. We changed our business model in 2002 to substantially eliminate our bulk and exchange activity due to the relatively low margins and high credit requirements for these transactions. Additionally, we reviewed our wellhead purchase contracts to determine whether margins under those contracts would support higher credit costs. In some cases, contracts were cancelled. These volume reductions began in late 2001 and continued into the first half of 2002. Volumes beginning in the third quarter of 2002 have remained relatively stable at an average of 57,500 barrels per day. For the fourth quarter of 2003, daily volumes were 61,400 barrels. The change in our business model was the primary reason crude oil gathering and marketing volumes decreased by 23%. Field operating costs primarily consist of the costs to operate our fleet of 49 trucks used to transport crude oil, and the costs to maintain the trucks and assets used in the crude oil gathering operation. Approximately 55% of these costs are variable and decline when volumes decline. Such costs include payroll and benefits (as drivers are paid on a commission basis based on volumes), maintenance costs for the trucks (as we lease the trucks under full service maintenance contracts under which we pay a maintenance fee per mile driven), and fuel costs. Fixed costs include the base lease payment for the vehicle, insurance costs and costs for environmental and safety related items. 22 Year Ended December 31, 2002 as Compared to Year Ended December 31, 2001 Gathering and marketing segment margins increased $1.4 million or 15% to $11.2 million for the year ended December 31, 2002, as compared to $9.7 million for the year ended December 31, 2001. The factors increasing segment margin were: - an $18.4 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and - an $0.8 million decrease in credit costs primarily due to the reduction in bulk and exchange transactions. Largely offsetting these increases were: - a 77 percent decrease in wellhead, bulk and exchange purchase volumes between 2001 and 2002, resulting in a decrease in segment margin of $17.1 million; and - a $0.7 million increase in field operating costs, primarily from a $0.3 million increase in payroll and benefits, a $0.2 million increase in repair costs, a $0.1 million increase in vehicle lease costs, and a $0.1 million increase in insurance costs. The increased payroll-related costs can be attributed to an increase in benefit costs and an increase in the miles driven in our trucks. The increased lease costs are attributable to increases in the number of vehicles and in the miles driven. The increase in repair costs is attributable primarily to repairs at truck unloading stations. The increased insurance costs reflect a combination of changes in the insurance market and our loss history. As discussed previously, we eliminated transactions with low margins and high credit costs. These volume reductions were the primary reasons gathering and marketing volumes decreased by 77% in the 2002 period. Outlook for 2004 and Beyond Volatility in P-Plus will continue. During 2004, we expect our crude oil gathering and marketing business to generate at least as much segment margin as it did in 2003; however, no assurance can be made that this will occur. Our plans include increasing volumes by acquiring new production and production currently being gathered by other parties. CRUDE OIL PIPELINE OPERATIONS We operate three common carrier pipeline systems in a five state area. We refer to these pipelines as our Texas System, Mississippi System and Jay System. Volumes shipped on these systems for the last three years are as follows (barrels per day):

Pipeline System 2003 2002 2001 --------------- ---- ---- ---- Texas 43,388 47,987 43,322 Mississippi 8,443 7,426 17,792 Jay 15,128 16,455 19,294

In 2003, we sold or abandoned significant portions of our Texas System. The segments we retained and continue to operate are from West Columbia to Webster, Cullen Junction to Webster, and from Webster to Texas City, and Webster to a shipper's facility in Houston. Information on the segments sold or abandoned is discussed in the section "Discontinued Operations" below. The following information pertains only to continuing operations. Volumes on our Texas System averaged 43,388 barrels per day in 2003. The crude oil that enters our system comes to us at West Columbia and Cullen Junction where we have connections to TEPPCO's South Texas System and at Webster where we have a connection with another pipeline. Under the terms of our sale to TEPPCO of portions of the pipeline, we have a joint tariff with TEPPCO through September 2004 under which we earn $0.40 per barrel on the majority of the barrels we deliver to the shipper's facilities and $0.50 per barrel on heavier crude oil we deliver. Most of the volume being shipped on our Texas System goes to three refineries on the Texas Gulf Coast. We are still shipping most of the same volumes that we were shipping before the sale to TEPPCO, however our tariff revenue is much less than before the sale, as we ship the crude oil a shorter distance. 23 The Mississippi System is best analyzed in two segments. The first segment is the portion of the pipeline that begins in Soso, MS and extends to Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest. The segment from Soso to Liberty has also been improved to handle the increased volumes produced by Denbury and transported on the pipeline. In order to handle future increases in production volumes in the area that are expected, we have made capital expenditures for tank, station and pipeline improvements and we will need to make further improvements. See Capital Expenditures under "Liquidity and Capital Resources" below. The second segment of the pipeline from Liberty to near Baton Rouge, LA has been out of service since February 1, 2002 while a connecting carrier tested its pipeline. The connecting carrier has decided not to reactivate its pipeline, so we will displace the crude oil in this segment with inhibited water until the connecting carrier either make repairs or we identify an alternative use for this segment. The cost of this displacement is being paid for by the owner of the crude oil. In 2003, this segment made no contribution to pipeline revenues. In 2002 and 2001, this segment of pipeline contributed $0.1 million and $1.5 million, respectively, to pipeline revenues. Volumes on this segment in 2001 were over 14,400 barrels per day. The Jay pipeline system in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Volumes have declined from an annual average of 19,294 per day in 2001, to 16,455 in 2002 to 15,128 in 2003. Many of the costs to operate our pipeline are fixed costs, including the costs of compliance with environmental regulations and the costs of insurance, so the decline in volumes has necessitated increases in tariffs. The only shipper on the largest portion of the pipeline has agreed to tariff rate increases in 2002 and 2003 that have helped offset the declines in the volumes and increased costs of operating this pipeline. Historically, the largest operating costs in our crude oil pipeline segment have consisted of personnel costs, power costs, maintenance costs and costs of compliance with regulations. Some of these costs are not predictable, such as failures of equipment, or are not within our control, like power cost increases. We perform regular maintenance on our assets to keep them in good operational condition to minimize any cost increases. Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 Pipeline segment margin decreased $0.3 million or 6% to $5.1 million for the year ended December 31, 2003, as compared to $5.4 million for the year ended December 31, 2002. The factors decreasing pipeline segment margin were: - a 7 percent decrease in throughput between the two years, resulting in a revenue decrease of $0.8 million; and - a $1.9 million increase in pipeline operating costs in 2003. In the third quarter we recorded an asset retirement obligation of $0.7 million related to an offshore pipeline. Pipeline operating costs increased $0.1 million for personnel and benefits costs related to addition as of operations staff in Mississippi and additions of staff engineers, and $0.1 million for costs associated with work vehicles for the new staff. Costs associated with maintenance of right-of ways, including clearing of tree canopies, and costs for testing under pipeline integrity regulations increased a combined $0.2 million. In 2003, we increased safety training for pipeline operations personnel at a cost of $0.3 million. Insurance costs increased $0.2 million due to the combination of insurance market conditions and our loss history. Other operating costs, including power costs increased a total of $0.3 million. Partially offsetting these decreases were the following factors: - a 22 percent increase in the average tariff on shipments resulting in a $2.3 million increase in revenue; and - a $0.1 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices resulting in more revenue on these volumes. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 Pipeline segment margin increased $2.5 million or 86% to $5.4 million for the year ended December 31, 2002, as compared to $2.9 million for the year ended December 31, 2001. The factors increasing pipeline segment margin were: 24 - a 35 percent increase in the average tariff on shipments resulting in a $2.9 million increase in revenue; and - a $1.6 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of revising pipeline tariffs to increase the amount of the pipeline loss allowance imposed on shippers, and the recognition of pipeline loss allowance volumes, measurement gains net of measurement losses, and crude quality deductions as inventory. Partially offsetting these increases were: - an 11 percent decrease in throughput between the two years, resulting in a revenue decrease of $1.0 million; and - a $1.0 million increase in pipeline operating costs in 2002 primarily due to greater expenditures for personnel and benefits, for maintenance of right-of-ways including clearing of tree canopies and costs associated with residential and commercial development around our pipelines, for testing under the pipeline integrity management regulations, for tank and station maintenance projects, for safety, training and related projects, for liability and property damage insurance, offset by lower costs for remote monitoring and control. Personnel and benefits costs increased $0.3 million primarily as a result of additions to the operations staff in Mississippi and costs associated with work vehicles for the new staff added $0.1 million. Costs associated with maintenance of right of ways and testing under pipeline integrity regulations increased a combined $0.1 million. In 2002, we increased safety training for our pipeline operations personnel at a cost of $0.1 million. Additionally we undertook a project to add Global Positioning Satellite information to our pipeline maps as required pursuant to pipeline safety regulations. Expenses incurred on this project in 2002 totaled $0.2 million. Insurance costs increased by $0.3 million due to the combination of insurance market conditions and our loss history. Our remote monitoring and control costs were lower by $0.1 million as we completed the transition in early 2002 from a more expensive service. Outlook for 2004 and Beyond After September 2004, we may continue to provide capacity to transport crude oil on our Texas System from Webster to Texas City and Houston. We expect to cease using the West Columbia to Webster segment and the Cullen Junction to Webster segment for crude oil service, as volumes shipped do not support the costs we would expect to incur to test and repair those segments of pipeline under the integrity management regulations. See discussion of the integrity management regulations in Safety Regulation under in "Item 1". If we continue to ship crude oil from Webster after September 2004, we would expect that we will receive it at Webster from new connections to other pipelines and receive less tariff income from those shipments than we are receiving under the current joint tariff with TEPPCO. We are also examining strategic opportunities to place the remaining segments in alternative service after the arrangement with TEPPCO expires. We expect that volumes may decline in 2004 as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's pipeline systems; however, those effects may not occur until the summer of 2004 when TEPPCO finishes its integration and connection of the segments acquired from us. As discussed above, the primary shipper on the segment of our Mississippi pipeline from Liberty to near Baton Rouge advised us in February 2004 that it does not have plans to reinstate shipments on this segment of pipeline. We currently plan to temporarily idle this segment of pipeline by removing the crude oil from the line while we evaluate future plans for this segment. Any future plans in crude oil service will require sufficient volumes being available to be transported on this segment of pipeline to justify the costs to perform the integrity testing and possible upgrading that may be necessary as a result of that testing. Future plans for this segment may include transportation of petroleum products or natural gas. Denbury is the largest oil and gas producer in Mississippi. Our Mississippi pipeline is adjacent to several of Denbury's existing and prospective oil fields. There may be mutual benefits to Denbury and us due to this common production and transportation area. Because of this relationship, we may be able to obtain certain commitments for increased crude oil volumes, while Denbury may obtain the certainty of transportation for its oil production at competitive market rates. As Denbury continues to acquire and develop old oil fields using CO2 based tertiary recovery operations, Denbury would expect to add crude oil gathering and CO2 supply infrastructure 25 to these fields. Further, as the fields are developed over time, it may create increased demand for our crude oil transportation services. The production shipped from oil fields surrounding our Jay system is a combination of new fields with estimated short production lives and older fields that have been producing for twenty to thirty years and are in the late stages of economic life. We believe that the highest and best use of the Jay system would be to convert it to natural gas service. We continue to review strategic alternatives with other parties in the region to explore this opportunity. This initiative is in a very preliminary stage. Part of the process will involve finding alternative methods for us to continue to provide crude oil transportation services in the area. While we believe this initiative has long-term potential, it is not expected to have a substantial impact on us during 2004 or 2005. Pipeline segment margins from continuing operations should remain flat or decline slightly in 2004. We expect volume increases on the Mississippi system and the tariff increases on the Jay system to substantially offset increases in fixed costs, including the costs for testing under the integrity management program. CARBON DIOXIDE (CO2) OPERATIONS In November 2003, we acquired a volumetric production payment of 167.5 Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the production payment, Denbury also assigned to us three of their existing long-term CO2 contracts with industrial customers. Denbury owns the pipeline that is used to transport the CO2 to our customers as well as to its own tertiary recovery operations. The industrial customers treat the CO2 and transport it to their own customers. The primary industrial applications of CO2 by these customers include beverage carbonation and food chilling and freezing. Based on Denbury's experience, we can expect some seasonality in our sales of CO2, as the dominant months for beverage carbonation and freezing food are from April to October, when warm weather drives up demand for beverages and the approaching holidays increase demand for frozen foods. The average daily Mcf for each month in 2003, 2002 and 2001 purchased under these contracts was as follows:

Month 2003 2002 2001 ----- ---- ---- ---- January 35,533 35,802 32,185 February 38,441 38,770 38,458 March 38,292 39,342 32,761 April 41,683 37,295 36,470 May 42,092 37,890 37,944 June 42,898 37,296 39,342 July 43,220 37,125 40,148 August 42,048 39,799 41,042 September 43,564 39,746 41,159 October 42,810 40,844 41,489 November 38,767 38,568 42,349 December 33,975 34,835 38,234

The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012, and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee from us of $0.16 per Mcf, subject to inflationary adjustments, for those transportation services. The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The maximum daily contract quantity per year in the contracts totals 48,750 Mcf. Under the minimum take or pay volumes, the customers must purchase a total of 14,468 Mcf per day whether received or not. Any volume purchased under the take-or-pay provision in any year can then be recovered in a future year as long as 26 the minimum requirement is met in that year. In the three years ended December 31, 2003, all three customers have purchased more than their minimum take-or-pay quantities, as can be seen in the table above. The three industrial contracts extend through 2010, 2012 and 2015. The sales contracts contain provisions for inflationary adjustments to sales prices based on the Producer Price Index, with a minimum price. During the two months we owned the CO2 assets in 2003, we earned revenues of $1.0 million and segment margin of $0.7 million. We expect to generate approximately $5 million of annual segment margin from this business during the first five years. The purchase of these assets provides us with diversity in our asset base and a stable long-term source of cash flow. DISCONTINUED OPERATIONS In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc.. We received no proceeds from the sale to Blackhawk. Other remaining segments not sold to these parties were abandoned in place. The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs and risks of operation. As a result of this evaluation we determined that parts of our Texas Gulf Coast operations were of more strategic value to TEPPCO than to us. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks. By selling these assets, we eliminated approximately $6.6 million of capital expenditures that we might have had to make depending on the results of IMP testing. TEPPCO paid us $21.6 million for the assets it acquired. We incurred transaction costs of $0.4 million which reduced the net proceeds to $21.2 million. TEPPCO also assumed responsibility for $0.6 million of unpaid royalties related to the crude oil purchase and sale contracts it assumed. We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period. We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to the sale date, subject to certain conditions. TEPPCO will pay the first $25,000 for each environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of that amount up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO for environmental matters in connection with this transaction will cease in ten years. We do not expect the effects of this indemnification to have a material effect on our results of operations in the future. During 2003, we recorded $0.4 million in termination benefits related to this sale. These benefits included retention bonuses and severance pay for employees affected by the sale. Under the terms of the sale to Blackhawk, we agreed to provide transition services through March 31, 2004. These transition services are not significant as the pipeline is idle. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years. 27 Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:

Year Ended December 31, --------------------------------------- 2003 2002 2001 --------- --------- --------- Revenues: Gathering and marketing ........................................... $ 263,930 $ 252,452 $ 324,371 Pipeline .......................................................... 6,480 6,726 4,247 --------- --------- --------- Total revenues ................................................. 270,410 259,178 328,618 Costs and expenses: Crude costs ....................................................... 256,986 243,262 313,202 Field operating costs ............................................. 4,718 4,535 4,379 Pipeline operating costs .......................................... 5,846 4,852 3,859 General and administrative ........................................ 282 425 384 Depreciation and amortization ..................................... 1,864 1,210 2,206 Change in fair value of derivatives ............................... -- 815 (578) Net gain on disposal of surplus assets ............................ -- (3) -- Impairment of long-lived assets ................................... -- -- 35,472 --------- --------- --------- Total costs and expenses ....................................... 26,696 255,096 358,924 --------- --------- --------- Operating income from discontinued operations .................. 714 4,082 (30,306) --------- --------- --------- Net proceeds from asset sales ........................................ 21,240 -- -- Net book value of assets sold ........................................ 8,212 -- -- --------- --------- --------- Gain on disposal of assets ........................................... 13,028 -- -- --------- --------- --------- Income from operations from discontinued Texas System before minority interests .................................. $ 13,742 $ 4,082 $ (30,306) ========= ========= =========

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2003 declined by $3.6 million, with $2.4 million of the decline resulting from crude oil gathering and marketing operations, and the remainder from pipeline operations. Margin from discontinued crude oil gathering and marketing operations declined due to the following: - an $0.8 million decrease in margin due to an decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; - a 15 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $1.4 million decrease in margin; and - a $0.2 million increase in field operating costs from termination benefits. Pipeline margin from discontinued operations decreased by $1.2 million due to the following: - a 2 percent decrease in the average tariff on shipments resulting in a $0.1 million decrease in revenue; - an 11 percent decrease in throughput between the two years, resulting in a $0.5 million revenue decrease; and - a $1.0 million increase in pipeline operating costs in 2003. Included in the pipeline operating costs in 2003 is $0.7 million for demolition and disposal costs for tanks and other equipment that were not sold and no longer had any use to us. We chose to perform this demolition in 2003 to reduce the taxable gain that would be allocated to many of our unitholders from the sale to TEPPCO. Also included in 2003 is $0.2 million for termination benefits incurred as a result of the sale to TEPPCO. Other operating costs increased a total of $0.1 million. These decreases were partially offset by a $0.4 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices. 28 General and administrative expenses include the direct costs of individuals involved only with the assets sold. The decrease in these costs resulted from the termination of those persons from our employment as a result of the sale. The increase in depreciation in 2003 as compared to 2002 resulted from the elimination of the remaining book value of assets not sold that no longer had any use to us. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2002 declined by $0.6 million. This amount is the net result of a $2.1 million decrease in margin from crude oil gathering and marketing operations, and a $1.5 million increase in margin from pipeline operations. Margin from crude oil gathering and marketing operations declined due to the following: - a 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a decrease in margin of $2.5 million; and - $0.1 million increases in both field operating and credit costs. Partially offsetting these decreases was a $0.6 million increase in margin due to a decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale. Pipeline margin increased by $1.5 million due to the following: - a 34 percent increase of in the average tariff on shipments resulting in a $1.4 million increase in revenue; - a 10 percent increase in throughput between the two years, resulting in a $0.4 million revenue increase; and - an increase in revenues from sales of pipeline loss allowance barrels of $0.7 million primarily as a result of higher crude oil market prices resulting in more revenue on these volumes. Partially offsetting these increases was a $1.0 million increase in pipeline operating costs in 2002. These increases included a $0.2 million increase in costs associated with maintenance of right of ways and testing under pipeline integrity regulations; tank and station maintenance expenses increased $0.2 million and safety training for our pipeline operations personnel increased $0.2 million. Insurance costs increased $0.1 million and the mapping project added $0.3 million to costs. In 2001, we recorded impairment of $35.5 related to the assets that were sold or abandoned in 2003. This impairment reduced the depreciation recorded in 2002. OTHER COSTS AND INTEREST Year Ended December 31, 2003 Compared with Year Ended December 31, 2002 General and administrative expenses. General and administrative expenses increased $0.9 million in 2003 from the 2002 level. Corporate governance costs including legal and consultant costs related to compliance with the Sarbanes-Oxley Act of 2002, increased directors fees and higher directors and officers insurance costs added $0.4 million. Other general and administrative costs increased by $0.1 million. Two other factors contributing to this increase were the write-off of $0.2 million of unamortized legal and consultant costs related to credit agreement with Citicorp and a non-cash charge of $0.2 million related to our new stock appreciation rights program for employees and directors (see Note 14 to the consolidated financial statements). The write-off of unamortized costs was necessitated by the replacement of the Citicorp credit facility in 2003 with a credit facility with Fleet National Bank. Under our bonus program, bonuses were eliminated unless distributions were being paid, which resulted in no accrual in 2002. We expect general and administrative expenses in 2004 to remain level with those of 2003. Consultant costs related to the internal documentation and assessment provisions of the Sarbanes-Oxley Act are expected to increase over 2003 levels, offsetting the 2003 write-off of credit facility costs. Change in fair value of derivatives. We designated our contracts as normal purchases and sales under the provisions for that treatment in SFAS No. 133. We did not engage in any derivative transactions during 2003, and 29 would expect to do so in 2004 only as needed. During 2002, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million. Other operating charges. In 2002, we reached an agreement in principle with the federal and state regulatory authorities regarding the fines we would pay related to the spill that occurred in December 1999 in Mississippi. The cost to us under the agreement is expected to be $3.0 million. In the fourth quarter of 2001 we accrued $1.5 million for this potential fine and in the third quarter of 2002 another $1.5 million was accrued. Interest expense, net. In 2003, our net interest expense decreased by $0.1 million. The primary factor was a decrease in March 2003 of the size of our credit facility from $80 million to $65 million. In 2002, the larger amount of the credit facility resulted in higher commitment fees. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 General and administrative expenses. General and administrative expenses decreased $3.4 million in 2002 from the 2001 level. Changes in personnel costs primarily due to the elimination of bulk and exchange activities reduced general and administrative expenses $2.3 million, and charges from our bonus program were $0.8 million less in 2002. The remaining decrease of $0.3 million is attributable to decreases in expenses for legal, tax and other professional services, offset by small increases in administrative insurance costs and contract labor costs. Depreciation, amortization and impairment. Depreciation and amortization expense decreased $1.7 million in 2002 from the 2001 level. As a result of the impairment of our pipeline assets in 2001, the value to be depreciated was reduced. The impairment recorded in 2001 was $9.6 million and related primarily to goodwill. Change in fair value of derivatives. As a result of the significant reduction in our bulk and exchange activities at December 31, 2001, and a review of contracts existing at December 31, 2002, we determined that substantially all of our contracts did not meet the requirement for treatment as derivative contracts under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended and interpreted). The contracts were designated as normal purchases and sales under the provisions for that treatment in SFAS No. 133. As a result, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million in 2002. Net gain on disposal of surplus assets. In 2002, we disposed of our seats on the NYMEX for $1.7 million, resulting in a gain of $0.5 million. The changes we made in our business model to reduce our bulk and exchange activities eliminated our reasons for owning the NYMEX seats. Additionally, in 2002, we sold surplus land, a building and surplus vehicles, resulting in additional cumulative net gains of $0.2 million. In 2000, we leased our tractor/trailer fleet from Ryder Transportation Services. The majority of the existing fleet was sold in 2000 and 2001. Cash proceeds of $0.4 million and a gain of $0.1 million in 2001 were realized in 2001 from this sale. Interest expense, net. In 2002, the Partnership had an increase in its net interest expense of $0.5 million. In 2001, the Partnership paid commitment fees on the unused portion of its $25 million facility with BNP Paribas. In the 2002 period, the Partnership paid commitment fees on the unused portion of its credit facility of $130 million in the first pat of the year and $80 million thereafter. The larger amount of the credit facility resulted in substantially higher commitment fees in 2002. LIQUIDITY AND CAPITAL RESOURCES Cash Flows Our primary sources of cash flows are operations, credit facilities, and in 2003, proceeds from the sale of a portion of our operations. Additionally in 2003, we issued limited partner interests to our general partner and received cash. Our primary uses of cash flows are capital expenditures and distributions. A summary of our cash flows for the years ended December 31, 2003, 2002 and 2001 is as follows (in thousands):

Year Ended December 31, ----------------------------------------------- 2003 2002 2001 ------------ ----------- ------------ Cash provided by (used in): Operating activities................................. $ 4,693 $ 7,417 $ 18,156 Investing activities................................. $ (6,994) $ (1,963) $ (1,429) Financing activities................................. $ 4,099 $ (10,160) $ (16,458)

30 Operating. Net cash from operating activities for each year have been comprised of the following (in thousands):

Year Ended December 31, ------------------------------------- 2003 2002 2001 -------- -------- -------- Net income ............................................. $ 13,322 $ 5,092 $(43,612) Depreciation, amortization and impairment .............. 7,535 6,549 52,630 Gain on sales of assets ................................ (13,264) (708) (167) Derivative related non-cash adjustments ................ 39 2,055 (2,726) Other non-cash items ................................... 229 1,500 1,601 Changes in components of working capital, net .......... (3,168) (7,071) 10,430 -------- -------- -------- Net cash from operating activities .................. $ 4,693 $ 7,417 $ 18,156 ======== ======== ========

Our operating cash flows are affected significantly by changes in items of working capital. We have had situations where other parties have prepaid for purchases or paid more than was due, resulting in fluctuations in one period as compared to the next until the party recovers the excess payment. While this happens infrequently, we did incorrectly receive $2.4 million in 2001 that was not repaid until 2003. During the 2001 period while we were actively engaged in bulk and exchange activities, our cash flows were affected by the differences in the timing between receiving the cash effects of derivative transactions and recording those transactions in net income. Affecting all periods is the timing of capital expenditures and their effects on our recorded liabilities. Cash management in the crude oil gathering and marketing business functions as follows. All purchases and sales are settled monthly with payment on the 20th of the following month. We receive payment for sales by wire transfer on the 20th. Approximately 75% of the obligations for purchases are also paid by wire transfer on the 20th. The remaining 25% of purchases are paid for by check. These checks, primarily to royalty owners and small oil companies, generally take five or six days to clear our bank account. This payment cycle provides several benefits to us. We know that substantially all of our receivables for crude oil sales will be collected on the 20th. We also defer payment until checks that were mailed clear our checking accounts. Our borrowings, and therefore our interest costs, are reduced for this short time period each month following the 20th. Similarly, tariffs are billed monthly and require payment ten days after the invoice date. Therefore collection of our pipeline accounts receivable is very rapid. Because shippers generally want to continue shipping, these receivables are generally paid quickly by our customers. Our accounts receivable settle monthly and collection delays generally relate only to discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered. Of the $66.7 million aggregate receivables on our consolidated balance sheet at December 31, 2003, approximately $65.4 million, or 98.1%, were less than 30 days past the invoice date. Investing. Cash flows used in investing activities in 2003 were $7.0 million as compared to $2.0 million in 2002. In 2003 we sold portions of our Texas pipeline system as well as other assets for $22.3 million net, and we expended $24.4 million to acquire the CO2 assets. Additionally we expended $4.9 million for other capital improvements. These expenditures included improvements on our Mississippi pipeline system to handle increased volumes more efficiently and effectively, additions and improvements totaling approximately $1.5 million on the Texas assets sold to TEPPCO in October 2003 and other equipment improvements. In 2002 we expended $4.2 million for property and equipment additions. These expenditures included replacement of pipe in Mississippi and Texas and upgrades to pipeline stations in Mississippi to handle larger volumes of crude oil throughput, including building new tanks. Offsetting these expenditures in 2002, were sales of surplus assets from which we received $2.2 million. In early 2002, we sold our two seats on the NYMEX for $1.7 million as discussed above. We also received $0.5 million from the sale of excess land with a building. In 2001, we expended $1.9 million for property and equipment, primarily in our pipeline operations. We received $0.5 million from the sale of tractors and trailers that were no longer needed as the fleet was replaced with new equipment leased from Ryder Transportation Inc. See additional detail on capital expenditures below. Financing. In 2003, financing activities provided net cash of $4.1 million. In November 2003, our general partner acquired from us 688,811 newly-issued Common Units and a proportionate general partner interest for $5.0 million. We also increased our outstanding debt by $1.5 million. We utilized $1.1 million of these funds to pay 31 fees related to the new credit facility with Fleet National Bank. Distributions to our partners utilized $1.3 million. Net cash expended for financing activities was $10.2 million in 2002 as compared to $16.5 million in 2001. In 2002 we reduced long-term debt outstanding at year end by $8.4 million from the balance at December 31, 2001. We also paid a special distribution of $0.20 per unit in December 2002, which utilized $1.8 million of cash. In 2001, we reduced debt by $8.1 million from the balance at December 31, 2000, and paid four quarterly distributions in the amount of $0.20 per unit each, which utilized $7.0 million of cash. Capital Expenditures A summary of our capital expenditures in the three years ended December 31, 2003, 2002, and 2001 is as follows (in thousands):

Year Ended December 31, ----------------------------------------- 2003 2002 2001 --------- --------- --------- Maintenance capital expenditures: Texas pipeline system ................................... $ 1,588 $ 1,638 $ 1,242 Mississippi pipeline system ............................. 1,684 1,838 222 Jay pipeline system ..................................... 213 43 10 Crude oil gathering assets .............................. 307 241 167 Administrative assets ................................... 384 451 241 --------- --------- --------- Total maintenance capital expenditures ............... 4,176 4,211 1,882 Growth capital expenditures: Mississippi pipeline system ............................. 76 -- -- Crude oil gathering assets .............................. 658 -- -- CO2 assets .............................................. 24,401 -- -- --------- --------- --------- Total growth capital expenditures .................... 25,135 -- -- --------- --------- --------- Total capital expenditures ........................ $ 29,311 $ 4,211 $ 1,882 ========= ========= =========

Maintenance capital expenditures in 2003 included a total of $0.5 million for installation of pipeline satellite monitoring capabilities on all three systems. Administrative asset expenditures included computer hardware and software. In the first half of 2003, we continued to upgrade the West Columbia to Markham segment of our Texas pipeline. The expenditures on the Mississippi system included additional improvements to the pipeline from Soso to Gwinville, where the crude oil spill had occurred in December 1999, to restore this segment to service. We also improved the pipeline from Gwinville to Liberty to be able to handle increased volumes on that segment by upgrading pumps and meters and completing additional tankage. Growth capital expenditures in 2003 included the acquisition of a condensate storage facility in Texas that was subsequently sold to TEPPCO and the acquisition of the CO2 assets from Denbury. Although we have no commitments to make capital expenditures, based on the information available to us at this time, we currently anticipate that our capital expenditures will be as follows (in thousands):

2004 2005 2006 ---- ---- ---- Maintenance capital expenditures: Texas System $ 106 $ 396 $ 199 Mississippi System 455 1,593 969 Jay System 30 145 75 Other 167 60 60 -------- --------- --------- Total $ 758 $ 2,194 $ 1,303 ======== ========= =========

In 2004, we expect the expenditures on our Texas system to relate primarily to corrosion control and in 2005 and 2006, to improvements to our control and monitoring system. The maintenance capital expenditure estimates for our Mississippi system include corrosion control expenditures, minor facility improvements and rehabilitation of the pipeline as a result of integrity management test results, as discussed below. 32 Complying with Department of Transportation Pipeline Integrity Management Program (IMP) regulations has been and will be a significant driver in determining the amount and timing of our capital expenditure requirements. On March 31, 2001, the Department of Transportation promulgated the IMP regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect High Consequence Areas (HCA). The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative technology. An HCA is defined as (a) a commercially navigable waterway; (b) an urbanized area that contains 50,000 or more people and has a density of at least 1,000 people per square mile; (c) other populated areas that contain a concentrated population, such as an incorporated or unincorporated city, town or village; and (d) an area of the environment that has been designated as unusually sensitive to oil spills. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. In accordance with the IMP regulations, we prepared a written Integrity Management Plan in 2002 that detailed our plans for testing and assessing each segment of the pipeline. The IMP regulations require that the baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. We expect to spend $0.6 million in 2004 and $0.2 million in 2005 for pipeline integrity testing that will be charged to pipeline operating expense as incurred. As testing is completed, we are required to take prompt remedial action to address integrity issues raised by the assessment. The rehabilitation action required as a result of the assessment and testing is expected to impact our capital expenditure program by requiring us to make improvements to our pipeline. This creates a difficult budgeting and planning challenge as we cannot predict the results of pipeline testing until they are completed. Based on estimated improvements required from assessments made during 2002 and 2003, we have estimated capital expenditures to be made during the IMP assessment period from 2004 through 2009. These capital expenditure projections are based on very preliminary data regarding the cost of rehabilitation. Such capital expenditure projections have been updated to eliminate the segments of the Texas system that were sold or abandoned in 2003, and the projections will be updated as improved data is obtained. During 2003 and 2002, $1.0 million and $1.7 million in capital expenditures were spent for rehabilitation of the Mississippi and Texas Pipeline Systems. Based on actual experience during 2003 and 2002 applied to our written IMP plan, we expect to spend $0.2 million, $1.2 million and $0.7 million in 2004, 2005 and 2006, respectively, for pipeline rehabilitation on the Mississippi System as a result of IMP testing. We currently do not expect to incur any rehabilitation expenditures on the other systems during this period. Expenditures on capital assets to grow the partnership will depend on our access to debt and capital discussed below in "Sources of Future Capital." Our focus will be on acquisitions that add stable cash flows to smooth out the volatility of the crude oil gathering business. Those acquisitions may include the acquisition of additional CO2 assets from Denbury and the construction of CO2 and crude oil pipelines to access Denbury's crude oil fields in Mississippi. Denbury owns additional CO2 industrial sales contracts that we might be able to purchase along with additional volume under our production payment. We may also construct and operate CO2 pipelines next to crude oil pipelines to supply Denbury's fields with the CO2 for tertiary recovery and then to move the resulting crude oil production to market. We will also look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. Capital Resources In March 2003, we entered into a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. The key terms of the Fleet Facility are as follows: - Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%. - The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%. 33 - We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%. - The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. - Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets. - The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders. We were in compliance with the Fleet Facility covenants at December 31, 2003. Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under "Distributions". At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. Outstanding letters of credit issued to Denbury for the purchase of crude oil at December 31, 2003, totaled $12.5 million, and are included in the $21.6 million total above. In February 2004, Denbury agreed to reduce by half its requirement to provide Denbury with letters of credit for our crude oil purchases from them. Sources of Future Capital Prior to 2003, we funded our capital commitments from operating cash and borrowings under bank facilities. In 2003, we issued common units to our general partner for cash and sold assets to fund growth. Our plans for the future include a combination of borrowings and the issuance of additional common units to the public. We have entered into discussions with Fleet National Bank regarding an expansion of our existing credit facility from $65 million to $100 million. We would like to reduce the amount of the facility committed to letters of credit and working capital borrowings from $65 million to $50 million and have $50 million available for acquisitions. We are in discussions with Fleet to determine the terms of the expanded facility. We may consider raising capital through an equity offering of additional common units if we make acquisitions using an expanded credit facility. Any such proceeds could be used to reduce the outstanding balances under the credit facility thereby freeing up debt capacity to use for additional accretive acquisitions. An equity offering would probably not occur before the fourth quarter of 2004. Distributions As a master limited partnership, the key consideration of our Unitholders is the amount of our distribution, its reliability and the prospects for distribution growth. Normally we distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 in total), which was paid in February 2004. 34 Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the distribution measured once each month in order for us to make a distribution for the quarter. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003. The likelihood and timing of the payment of any incentive distributions will depend on our ability to make accretive acquisitions and generate cash flows from of those acquisitions. We do not expect to make incentive distributions during 2004. We believe we will be able to sustain a regular quarterly distribution at $0.15 per unit during 2004. We do not expect to be able to restore the distribution to the targeted minimum quarterly distribution level of $0.20 per unit until 2005. However, if we exceed our expectations for improving the performance of the business, if our capital projects cost less than we currently estimate, or if our access to capital allows us to make accretive acquisitions, we may be able to restore the targeted minimum quarterly distribution sooner. Available Cash before reserves for the year ended December 31, 2003, is as follows (in thousands): Net income................................................... $ 13,322 Depreciation and amortization................................ 6,504 Excluded gain from asset sales............................... (13,088) Cash proceeds in excess of gains on certain asset sales...... 879 Non-cash charges............................................. 229 Maintenance capital expenditures............................. (4,176) ----------- Available Cash before reserves............................... $ 3,670 =========== Available Cash (a non-GAAP liquidity measure) has been reconciled to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003 below. The non-GAAP financial measure of Available Cash is calculated in accordance with generally accepted accounting principles (GAAP), with the exception of maintenance capital expenditures as used in our calculation of Available Cash. Maintenance capital expenditures are capital expenditures (as defined by GAAP) to replace or enhance partially or fully depreciated assets in order to sustain the existing operating capacity or efficiency of our assets and extend their useful lives. We believe that investors benefit from having access to the same financial measures being utilized by management. Available Cash is a liquidity measure used by our management to compare cash flows generated by the Partnership to the cash distribution we pay to our limited partners and the general partner. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure tells investors whether or not the Partnership is generating cash flows at a level that can support a quarterly cash distribution to our partners. Lastly, Available Cash (also referred to as distributable cash flow) is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships. Several adjustments to net income are required to calculate Available Cash. These adjustments include: (1) the addition of non-cash expenses such as depreciation and amortization expense; (2) miscellaneous non-cash adjustments such as the addition of decreases or the subtraction of increases in the value of financial instruments; and (3) the subtraction of maintenance capital expenditures. See "Distributions" above. The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003, is as follows (in thousands): 35

Year Ended December 31, 2003 ------------ Cash flows from operating activities................................. $ 4,693 Adjustments to reconcile operating cash flows to Available Cash: Maintenance capital expenditures................................. (4,176) Proceeds from sales of certain assets............................ 1,055 Change in fair value of derivatives.............................. (39) Amortization of credit facility issuance fees.................... (1,031) Net effect of changes in operating accounts not included in calculation of Available Cash..................... 3,168 --------- Available Cash before reserves....................................... $ 3,670 =========

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS Contractual Obligation and Commercial Commitments In addition to the Fleet Facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes our obligations and commitments at December 31, 2003 (in thousands).

Payments Due by Period ----------------------------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations 1 Year Years Years Years Total -------- -------- -------- -------- -------- Long-term Debt ..................... $ -- $ 7,000 $ -- $ -- $ 7,000 Operating Leases ................... 3,048 3,539 1,074 935 8,596 Pennzoil litigation settlement ...................... 12,750 -- -- -- 12,750 Mississippi oil spill fine ......... 3,000 -- -- -- 3,000 Offshore pipeline removal ......................... 700 -- -- -- 700 Unconditional Purchase Obligations ..................... 89,436 -- -- -- 89,436 -------- -------- -------- -------- -------- Total Contractual Cash Obligations ..................... $108,934 $ 10,539 $ 1,074 $ 935 $121,482 ======== ======== ======== ======== ========

In December 2003, our insurers settled litigation with Pennzoil-Quaker State for $12.8 million. (see Note 18 to the consolidated financial statements.) We have recorded in accrued liabilities on our consolidated statement of operations the obligation for this settlement, and we have recorded the insurance reimbursement for this obligation in insurance receivable. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and with our funding the remaining $6.9 million. We expect to receive reimbursement from the insurance company no later than May 2004. We expect to pay the estimated $3.0 million fine related to the Mississippi oil spill that occurred in 1999 (see Note 18 to the consolidated financial statements) during the second quarter of 2004. We expect to incur approximately $0.7 million to remove an abandoned offshore pipeline during the second quarter of 2004. While the temporary funding of the litigation settlement and the payment of the fine and pipeline removal costs will increase our average outstanding debt during 2004, we believe we have sufficient capacity under the Fleet Facility to meet these obligations. Off-Balance sheet Arrangements We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed in this section, nor do we have any debt or equity triggers based upon our unit or commodity prices. 36 OTHER MATTERS Risk Factors Related to Our Business The success of our crude oil gathering, marketing and pipeline operations is dependent upon increases in the availability of crude oil supplies and our ability to secure those supplies. Securing additional supplies of crude oil from increased production by oil companies and by aggressive lease gathering efforts depends partially on the ability of oil producers to increase production. Factors affecting an increase in production can include the prevailing market price for oil, the exploration and production budgets of the major and independent oil companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters that are beyond our control. The profitability of our crude oil gathering and marketing operations depends primarily on the volumes of crude oil we purchase and gather. Natural declines in crude oil production from depleting wells or volumes lost to competitors must be replaced by contracts for new supplies of crude oil so as to maintain the volumes of crude oil we purchase. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil. Our operations are dependent upon demand for crude oil by refiners in the Gulf Coast and Midwest. Any decrease in this demand could adversely affect our business. This demand is dependent on the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. We face intense competition in our crude oil gathering and marketing activities. Our competitors include independent gatherers, the major integrated oil companies and their marketing affiliates and other marketers of various sizes, financial resources and experience. Many of these competitors have capital resources many times greater than ours and control much greater supplies of crude oil. We are exposed to the credit risk of our customers in the ordinary course of our crude oil gathering and marketing operations. There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counter-parties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us. In those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for the distribution of proceeds to all parties. In other cases, we pay all or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties. The profitability of our crude oil pipeline operations depends on the volume of crude oil shipped by third parties and on our interconnections with other crude oil pipelines. Third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. Additionally, in Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our profitability. Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines can result in less demand for our transmission services. Our operations are subject to federal and state environmental and safety regulations and laws related to environmental protection and operational safety. Our crude oil gathering and pipeline operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or 37 claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through greater margins, higher tariffs or insurance reimbursements; our cash flows and results of operations could be materially impacted. The transportation and storage of crude oil results in a risk that crude oil and related hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. Certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes gathered by truck or transmitted by our pipelines. As a result, we may experience declines in segment margin and profitability should our volumes decrease. Our CO2 operations are exposed to risks related to Denbury's operation of their CO2 fields, equipment and pipeline. Because Denbury produces the CO2 and transports the CO2 to our customers, any long-term failure of their operations could have an impact on our ability to meet our obligations to our CO2 customers. We have no other supply of CO2 or method to transport it to our customers. Fluctuations in demand for CO2 by our industrial customers could materially impact our profitability. Our customers are not contractually obligated to purchase volumes in excess of the take-or-pay amounts in the contracts. The customers have processing facilities located at the delivery points on Denbury's pipeline. Fluctuations in their demand due to market forces or operational problems could result in a reduction in our revenues from the sales of CO2. The CO2 supplied by Denbury to us for our sale to our customers could fail to meet the quality standards in the contracts due to impurities or water vapor content. If the CO2 were below specifications, we could be contractually obligated to provide compensation to our customers for the costs incurred in raising the CO2 quality to serviceable levels. Our wholesale CO2 industrial marketing operations are dependent on three customers. Should one or more of those customers experience financial difficulties such that they fail to purchase their required minimum take-or-pay volume and fail to compensate us for the lost revenue, our profitability could be materially impacted. The three customers appear to be credit worthy, however there can be no assurance that an unanticipated deterioration in their ability to meet their obligations to us might not occur. Newly acquired properties could expose us to environmental liabilities and increased regulatory compliance costs. Our business plan includes making acquisitions to increase our cash flows. Assets that we may acquire will likely have associated environmental liabilities, as well as required compliance with regulations such as the integrity management program for regulated pipelines. Although we will attempt to identify such exposures and address the associated costs through indemnities, purchase price adjustments or insurance, we may incur costs not covered by indemnity, insurance or reserves. Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of reserves. Because distributions to our unitholders are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made in periods when we record losses and might not be made during periods when we record profits. The terms of our credit facility may limit our ability to borrow additional funds, make distributions to unitholders, or capitalize on business opportunities. Our credit facility includes limitations on our ability to make distributions to our unitholders and require approval of lenders to take certain actions. Any refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it could substantially reduce distributions to our unitholders and might reduce 38 our ability to grow the business. The after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal and state income tax purposes. If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Some or all of the distributions made to unitholders would be treated as dividend income, and no income, gains, losses or deductions would flow through to unitholders. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the unitholders. We believe a substantial number of our Common Units are held by entities that derive a tax benefit from investment in partnership-type entities with large gross receipts. Should a change occur such that our revenues declined to a level that these investors might find alternative sources for this tax benefit other than by ownership in our Common Units, an adverse change in our unit price could take place. This condition could occur at the same time that we would be growing our distribution or otherwise increasing the value of our Common Units to the general investing public. Crude Oil Contamination We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurers settled this litigation for $12.8 million. We have recorded in accrued liabilities on our consolidated balance sheet the obligation for this settlement, and, in insurance receivable, we have recorded the insurance reimbursement for this obligation. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million funded by us. We expect to receive reimbursement from the insurance company no later than May 2004 for the portion funded by us. The settlement of this litigation had no effect on our results of operations. PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter. Insurance We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance policies are subject to deductibles that we consider reasonable. The policies do not cover every potential risk associated with operating our assets, including the potential for a loss of significant revenues. Consistent with the coverage available in the industry, our policies provide limited pollution coverage, with broader coverage for sudden and accidental pollution events. Additionally, as a result of the events of September 11, the cost of insurance available to the industry has risen significantly, and insurers have excluded or reduced coverage for losses due to acts of terrorism and sabotage. Since September 11, 2001, warnings have been issued by various agencies of the United States Government to advise owners and operators of energy assets that those assets may be a future target of terrorist organizations. Any future terrorist attacks on our assets, or assets of our customers or competitors could have a material adverse effect on our business. We believe that we are adequately insured for public liability and property damage to others as a result of our operations. However, no assurances can be given that an event not fully insured or indemnified against will not materially and adversely affect our operations and financial condition. Additionally, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. NEW ACCOUNTING PRONOUNCEMENTS SFAS 143 In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement 39 obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard was effective for us on January 1, 2003. With respect to our pipelines, federal regulations require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon expiration of the lease term. For our pipelines, we are unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations would be settled. For the truck unload stations, the site leases have provisions such that the lease continues until one of the parties gives notice that it wishes to end the lease. At this time we cannot reasonably estimate when such notice would be given and when the obligations to remove our improvements would be settled. We will record asset retirement obligations in the period in which we determine the settlement dates. In the third quarter of 2003, we recorded an obligation to remove a pipeline from offshore waters as a result of this standard. This pipeline has been out of service since 1998. The State of Louisiana advised us that the pipeline should be removed. We expect to remove this pipeline during 2004. SFAS 145 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions related to the rescission of SFAS No. 4 were applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 were effective for transactions occurring after May 15, 2002. All other provisions were effective for financial statements issued on or after May 15, 2002, with early application encouraged. The adoption of this statement did not have a material effect on our results of operations. SFAS 146 On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the date of commitment to an exit plan. This adoption of this statement on January 1, 2003, had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 to the consolidated financial statements. Interpretation No. 45 We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18 to the consolidated financial statements. 40 Interpretation No 46 In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements. SFAS 148 We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements. SFAS 149 On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. SFAS 150 In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our primary price risk relates to the effect of crude oil price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. We utilize NYMEX commodity based futures contracts and forward contracts to hedge our exposure to these market price fluctuations as needed. At December 31, 2003, we had no contracts outstanding. At December 31, 2003, we held 49,000 barrels of crude oil in inventory with a carrying cost of $1.5 million. The market value of this inventory at December 31, 2003 was $30,000 greater than its cost. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Consolidated Financial Statements" on page 52. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. ITEM 9A. CONTROLS AND PROCEDURES We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K and have determined that such disclosure 41 controls and procedures are adequate and effective in all material respects in providing to them on a timely basis material information relating to us (including our consolidated subsidiaries) required to be disclosed in this annual report. There have been no significant changes in our internal controls over financial reporting during the three months ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT We do not directly employ any persons responsible for managing or operating the Partnership or for providing services relating to day-to-day business affairs. The General Partner provides such services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. The Board of Directors of the General Partner (the "Board") consists of eight persons. Four of the directors, including the Chairman of the Board, are executives of Denbury. Our Chief Executive Officer serves on the Board. The three remaining directors are independent of Genesis and Denbury or any of its affiliates. Directors and Executive Officers of the General Partner Set forth below is certain information concerning the directors and executive officers of the General Partner. All executive officers serve at the discretion of the General Partner.

Name Age Position ---- --- -------- Gareth Roberts................ 51 Director and Chairman of the Board Mark J. Gorman................ 49 Director, Chief Executive Officer and President Ronald T. Evans............... 41 Director Herbert I. Goodman............ 81 Director Susan O. Rheney............... 44 Director Phil Rykhoek.................. 47 Director J. Conley Stone............... 72 Director Mark A. Worthey............... 46 Director Ross A. Benavides............. 50 Chief Financial Officer, General Counsel and Secretary Kerry W. Mazoch............... 57 Vice President, Crude Oil Acquisitions Karen N. Pape................. 46 Vice President and Controller

Gareth Roberts has served as a Director and Chairman of the Board of the General Partner since May 2002. Mr. Roberts is President, Chief Executive Officer and a director of Denbury Resources Inc. and has served in those capacities since 1992. Mr. Roberts also serves on the board of directors of Belden & Blake Corporation. Mark J. Gorman has served as a Director of the General Partner since December 1996 and as President and Chief Executive Officer since October 1999. From December 1996 to October 1999 he served as Executive Vice President and as Chief Operating Officer from October 1997 to October 1999. He was President of Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from September 1992 to December 1996. Ronald T. Evans has served as a director of the General Partner since May 2002. Mr. Evans is Senior Vice President of Reservoir Engineering of Denbury and has served in that capacity since September 1999. Before joining Denbury, Mr. Evans was employed as Engineering Manager with Matador Petroleum Corporation for three years and employed by Enserch Exploration, Inc. for twelve years in various positions. Herbert I. Goodman has served as a director of the General Partner since January 1997. He is the Chairman of IQ Holdings, Inc., a manufacturer and marketer of petrochemical-based consumer products. During 2001, he served as the Chief Executive Officer of PEPEX.NET, LLC, which provides electronic trading solutions to the international oil industry. Since 2002 he has served as Chairman of PEPEX.NET, LLC. From 1988 until 1996 he was Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading and consulting business. 42 Susan O. Rheney became a Director of the General Partner in March 2002. Ms. Rheney is a private investor and formerly was a principal of The Sterling Group, L.P., a private financial and investment organization, from 1992 to 2000. Ms. Rheney is a director of Texas Petrochemical Holdings, Inc., a chemical manufacturer, where she serves on the audit and finance committees. She is also a director of Mail-Well, Inc., a supplier of printing services and products, where she serves on the audit and governance and nominating committees. Phil Rykhoek has served as a director of the General Partner since May 2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President, Secretary and Treasurer of Denbury, and has served in those capacities since 1995. J. Conley Stone has served as a director of the General Partner since January 1997. From 1987 to his retirement in 1995, he served as President, Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe Line Company, a common carrier liquid petroleum products pipeline transporter. Mark A. Worthey has served as a director of the General Partner since May 2002. Mr. Worthey is Senior Vice President, Operations for Denbury and has been with Denbury since September 1992. Ross A. Benavides has served as Chief Financial Officer of the General Partner since October 1998. He has served as General Counsel and Secretary since December 1999. Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of the General Partner since August 1997. From 1991 to 1997 he held the position of Vice President and General Manager of Crude Oil Acquisitions at Northridge Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines Limited. Karen N. Pape was named Vice President and Controller of the General Partner effective in March 2002. Ms. Pape has served as Controller and as Director of Finance and Administration of the General Partner since December 1996. From 1990 to 1996, she was Vice President and Controller of Howell Corporation. Board Committees The Audit Committee consists of Susan O. Rheney, Herbert I. Goodman and J. Conley Stone. The Audit Committee has been established in accordance with SEC rules and regulations, and all members are independent directors as defined under the rules of the American Stock Exchange. The Board of Directors believes that Susan O. Rheney qualifies as an audit committee financial expert as such term is used in the rules and regulations of the SEC. The committee engages our independent auditors and oversees our independence from the auditors, pre-approves any services provided by our independent auditors, oversees the quality and integrity of our financial reports and our systems of internal controls with respect to finance, accounting, legal compliance and ethics, and oversees our anonymous complaint procedure established for our employees. The Audit Committee adopted a written Audit Committee charter on August 7, 2003. The full text of the Audit Committee charter is available on our website. Additionally, the General Partner is authorized to seek special approval from the Audit Committee of any resolution of a potential conflict of interest between the General Partner or of any of its affiliates and the Partnership or any of its affiliates. The Board has established a compensation committee to oversee compensation decisions for the employees of the General Partner, as well as the compensation plans of the General Partner. The members of the Compensation Committee are Gareth Roberts, Susan O. Rheney and Herbert I. Goodman, all of whom are non-employee directors of the General Partner. Code of Ethics We have adopted a code of ethics that is applicable to, among others, the principal financial officer and the principal accounting officer. The Genesis Energy Financial Employee Code of Professional Conduct is posted at our website, where we intend to report any changes or waivers. Section 16(a) Compliance Section 16(a) of the Securities Exchange Act of 1934 requires the officers and directors of the General Partner and persons who own more than ten percent of a registered class of the equity securities of the Partnership to file reports of ownership and changes in ownership with the SEC and the American Stock Exchange. Based solely on its review of the copies of such reports received by it, or written representations from certain reporting persons that 43 no Forms 5 was required for those persons, we believe that during 2003 its officers and directors complied with all applicable filing requirements in a timely manner. ITEM 11. EXECUTIVE COMPENSATION EXECUTIVE OFFICER COMPENSATION Under the terms of the Partnership Agreement, we are required to reimburse the General Partner for expenses relating to the operation of the Partnership, including salaries and bonuses of employees employed on behalf of the Partnership, as well as the costs of providing benefits to such persons under employee benefit plans and for the costs of health and life insurance. See "Certain Relationships and Related Transactions." Summary Compensation Table The following table summarizes certain information regarding the compensation paid or accrued by Genesis during 2003, 2002, and 2001 to the Chief Executive Officer and each of our three other executive officers (the "Named Officers").

Long-Term Compensation Annual Compensation Awards -------------------------------------- --------------- Securities Other Annual underlying All Other Salary Bonus Compensation SARs Granted(2) Compensation Name and Principal Position Year $ $ $(1) # $ --------------------------- ---- ------- ----- ------------ --------------- ------------ Mark J. Gorman 2003 275,000 4,070 12,755 23,620 15,000(3) Chief Executive Officer 2002 270,000 5,193 -- -- 11,500(4) and President 2001 270,000 56,814 -- -- 10,200(5) Ross A. Benavides 2003 185,000 2,738 8,580 15,889 13,803(6) Chief Financial Officer, 2002 180,000 3,462 -- -- 11,500(4) General Counsel and 2001 175,000 54,785 -- -- 10,200(5) Secretary Kerry W. Mazoch 2003 175,000 2,590 8,116 15,030 13,023(7) Vice President, Crude 2002 170,000 3,270 -- -- 11,478(8) Oil Acquisitions 2001 169,000 30,720 -- -- 10,200(5) Karen N. Pape 2003 141,000 2,094 6,563 12,153 10,533(9) Vice President and 2002 136,000 2,616 -- -- 10,118(10) Controller

(1) Represents the value deemed to have been "earned" during the year under the Stock Appreciation Rights Plan discussed below. No Named Officer had other "Perquisites and Other Personal Benefits" with a value greater than the lesser of $50,000 or 10% of reported salary and bonus. (2) SARs are Stock Appreciation Rights. See additional information in the table below. (3) Includes $9,000 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan. (4) Includes $5,500 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan. (5) Includes $5,100 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. (6) Includes $8,282 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan. (7) Includes $7,802 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan 44 (8) Includes $5,500 of Company-matching contributions to a defined contribution plan and $5,978 of profit-sharing contributions to a defined contribution plan. (9) Includes $6,320 of Company matching contributions to a defined contribution plan and $4,213 of profit-sharing contributions to a defined contribution plan. (10) Includes $5,059 of Company-matching contributions to a defined contribution plan and $5,059 of profit-sharing contributions to a defined contribution plan. Stock Appreciation Rights Plan In December 2003, the Board approved a Stock Appreciation Rights plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit. The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below. Upon vesting, the participant may exercise his rights to receive a cash payment equal to the difference between the average of the closing market price of Genesis Energy, L.P. Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date. Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested. On December 31, 2003, the initial award of rights was made to employees and directors. The following tables show the stock appreciation rights granted to the Executive Officers and the values of the stock appreciation rights at December 31, 2003. Information on rights granted to non-employee directors is included in the section entitled Director Compensation. SAR Grants During the Year Ended December 31, 2003

Individual Grants -------------------------------------------------------------------------------------------- Potential realizable value at Number of Percent Grant assumed annual rates of Securities of total date stock price appreciation underlying SARs granted Exercise closing for SAR term SARs to employees price price Expiration ----------------------------- Name granted (#) in fiscal year $/Unit $/Unit date 5%($) 10%($) ----------------- ----------- -------------- -------- ------- ---------- ------- ------- Mark J. Gorman 23,620 5.8% 9.26 9.80 12/31/2013 137,553 348,585 Ross A. Benavides 15,889 3.9% 9.26 9.80 12/31/2013 92,531 234,491 Kerry W. Mazoch 15,030 3.7% 9.26 9.80 12/31/2013 87,528 221,814 Karen N. Pape 12,153 3.0% 9.26 9.80 12/31/2013 70,774 179,355

December 31, 2003 SAR Values 45

Number of Common Units Value of underlying unexercised unexercised in-the-money SARs at December 31, 2003 (#) SARs at December 31, 2003 ($) ----------------------------- ----------------------------- Name Exercisable Unexercisable Exercisable Unexercisable ------------------ ----------- ------------- ----------- ------------- Mark J. Gorman -- 23,620 -- 12,755 Ross A. Benavides -- 15,889 -- 8,580 Kerry W. Mazoch -- 15,030 -- 8,116 Karen N. Pape -- 12,153 -- 6,563

Bonus Plan In May 2003, the Compensation Committee of the Board of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the financial performance of the Partnership by rewarding employees for achieving financial performance objectives. The Bonus Plan is administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a maximum bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash. Bonuses will be paid to employees after the end of the year. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and the General Partner can amend or change the Bonus Plan at any time. DIRECTOR COMPENSATION Information regarding the compensation received from the General Partner by Mr. Gorman, President, Chief Executive Officer and a director of the General Partner, is disclosed under the heading "Executive Officer Compensation". Directors Fees The three independent directors receive an annual fee of $30,000. The Audit Committee Chairman receives an additional annual fee of $4,000 and all members of the Audit Committee receive $1,500 for attendance at each committee meeting. Denbury receives $120,000 from the Partnership for providing four of its executives as directors. Mr. Gorman does not receive a fee for serving as a director. Stock Appreciation Rights The non-employee directors received stock appreciation rights under the same terms as the Executive Officers. Grants issued to directors during 2003 were:

Number of Securities underlying Exercise SARs price Expiration Name granted (#) $/Unit date -------------------- ----------- --------- ---------- Gareth Roberts 2,576 9.26 12/31/2013 Ronald T. Evans 2,576 9.26 12/31/2013 Herbert I. Goodman 3,092 9.26 12/31/2013 Susan O. Rheney 3,435 9.26 12/31/2013 J. Conley Stone 3,092 9.26 12/31/2013 Mark A. Worthey 2,576 9.26 12/31/2013

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 46 Beneficial Ownership of Partnership Units The following table sets forth certain information as of February 28, 2004, regarding the beneficial ownership of our units by beneficial owners of 5% or more of the units, by directors and the executive officers of our general partner and by all directors and executive officers as a group. This information is based on data furnished by the persons named.

Beneficial Ownership of Common Units ------------------------------------ Percent Title of Class Name Number of Units of Class -------------------- -------------------- --------------- -------- Genesis Energy, L.P. Genesis Energy, Inc. 688,811 7.4 Common Unit Gareth Roberts 10,000 * Mark J. Gorman 25,525 * Ronald T. Evans 1,000 * Herbert I. Goodman 2,000 * Susan O. Rheney 700 * Phil Rykhoek 4,000 * J. Conley Stone 1,000 * Mark A. Worthey 1,600 * Ross A. Benavides 9,283 * Kerry W. Mazoch 8,669 * Karen N. Pape 3,386 * All directors and executive officers as a group (11 in number) 67,163 *

---------- * Less than 1% Each unitholder in the above table is believed to have sole voting and investment power with respect to the shares beneficially held. Included in the units held by Mark A Worthey are 500 units held for a minor child. Included in the units held by Kerry W. Mazoch are 584 units held with his children. Beneficial Ownership of General Partner Interest Genesis Energy, Inc. owns all of our 2% general partner interest and all of our incentive distribution rights, in addition to 7.4% of our units. Genesis Energy, Inc. is a wholly-owned subsidiary of Denbury Resources, Inc. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Our General Partner Our operations are managed by, and our employees are employed by, Genesis Energy, Inc., our general partner. Our general partner does not receive any management fee or other compensation in connection with the management of our business, but is reimbursed for all direct and indirect expenses incurred on our behalf. During 2003, these reimbursements totaled $16.0 million. At December 31, 2003, we owed the general partner $0.1 million related to these services. Our general partner owns the 2% general partner interest and all incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.3% of amounts we distribute in excess of $0.25 per unit, 23.5% of the amounts we distribute in excess of $0.28 per unit, and 49% of the amounts we distribute in excess of $0.33 per unit. Relationship with Denbury Resources, Inc. Through its control of our general partner, Denbury has the ability to control our management. During 2003, we acquired a CO2 volumetric production payment and related wholesale marketing contracts from Denbury for $24.4 million. Additionally we enter into transactions with Denbury in the ordinary course of its operations. During 2003, these transactions included: 47 - Purchases of crude oil from Denbury totaling $59.7 million. We provide letter of credit to Denbury related to these purchases. - Provision of CO2 transportation services to our wholesale industrial customers by Denbury's pipeline. The fees for this service totaled $0.4 million in 2003. - Provision of services by Denbury officers as directors of our general partner. We paid Denbury $120,000 for these services in 2003. At December 31, 2003, we owed Denbury $6.9 million for purchases of crude oil and $0.1 million for transportation services. In 2002, we amended our partnership agreement to broaden the right of the Common Unitholders to remove the General Partner. Prior to this amendment, the general partner could only be removed for cause and with approval by holders of two-thirds or more of the outstanding limited partner interests in GELP. As amended, the partnership agreement provides that, with the approval of at least a majority of the limited partners in GELP, the general partner also may be removed without cause. Any limited partner interests held by the general partner and its affiliates would be excluded from such a vote. The amendment further provides that if it is proposed that the removal is without cause and an affiliate of Denbury is the general partner to be removed and not proposed as a successor, then any action for removal must also provide for Denbury to be granted an option effective upon its removal to purchase GELP's Mississippi pipeline system at a price that is 110 percent of its fair market value at that time. Fair value is to be determined by agreement of two independent appraisers, one chosen by the successor general partner and the other by Denbury or if they are unable to agree, the mid-point of the values determined by them. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following table summarizes the aggregate fees billed to us by Deloitte & Touche LLP.

2003 2002 ---- ---- (in thousands) Audit Fees (a)....................................... $ 211 $ 140 Audit-Related Fees (b)............................... 92 71 --------- --------- Total................................................ $ 303 $ 211 ========= =========

(a) Fees for audit services billed in 2003 consisted of: Audit of our annual financial statements Audit of our General Partner financial statements Reviews of our quarterly financial statements Financial statement audits of prior years that were originally audited by Arthur Andersen LLP. Fees for audit services billed in 2002 consisted of: Audit of our annual financial statements Reviews of our quarterly financial statements. (b) Fees for audit-related services in 2003 and 2002 consisted of: Financial accounting and reporting consultations Sarbanes-Oxley Act, Section 404 advisory services Employee benefit plan audits. Deloitte provided no tax services or other services to us in 2002 or 2003. In considering the nature of the services provided by Deloitte, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with Deloitte and management of our General Partner to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants. 48 Pre-Approval Policy The services by Deloitte in 2003 were pre-approved in accordance with the pre-approval policy and procedures adopted by the Audit Committee at its May 9, 2003 meeting. This policy describes the permitted audit, audit-related, tax and other services (collectively, the "Disclosure Categories") that the independent auditor may perform. The policy requires that prior to the beginning of each fiscal year, a description of the services (the "Service List") expected to be performed by the independent auditor in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval. Services provided by the independent auditor during the following year that are included in the Service List were pre-approved following the policies and procedures of the Audit Committee. Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meeting. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Consolidated Financial Statements" set forth on page 52. (a)(3) Exhibits 3.1 Certificate of Limited Partnership of Genesis Energy, L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545) 3.2 Third Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31, 2002) 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996) 3.4 Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.1 to Form 8-K dated July 31, 2002) 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"), Howell Corporation ("Howell"), certain subsidiaries of Howell, Genesis, the Operating Partnership and Genesis Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for the year ended December 31, 1996) 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended December 31, 1996) 10.3 Office Lease at One Allen Center between Trizec Allen Center Limited Partnership (Landlord) and Genesis Crude Oil, L.P. (Tenant) (incorporated by reference to Exhibit 10 to Form 10-Q for the quarterly period ended September 30, 1997) 10.4 Credit Agreement dated as of March 14, 2003, between Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet National Bank and Certain Financial Institutions (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2002) 10.5 Pipeline Sale and Purchase Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and Genesis Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K dated October 31, 2003) 10.6 Purchase and Sale Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K dated October 31, 2003) *10.7 Production Payment Purchase and Sale Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. executed November 14, 2003 49 *10.8 Carbon Dioxide Transportation Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. *10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan. 11.1 Statement Regarding Computation of Per Share Earnings (See Notes 2 and 7 to the Consolidated Financial Statements) *21.1 Subsidiaries of the Registrant *31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification by Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ---------- * Filed herewith + A management contract or compensation plan or arrangement. (b) Reports on Form 8-K A Current Report on Form 8-K was filed on November 24, 2003, in connection with the purchase of a volumetric production payment from Denbury. A Current Report on Form 8-K was furnished on November 11, 2003, providing, under Items 7, 9 and 12, the Partnership's news release including attached schedules dated November 11, 2003, that announced the Partnership's financial and operating results for the three and nine month periods ended September 30, 2003. A Current Report on Form 8-K was filed on November 4, 2003, including, as an exhibit, pro forma financial statements, in connection with the sale of parts of the Partnership's crude oil pipeline and associated gathering and marketing operations. A Current Report on Form 8-K was furnished October 15, 2003, providing, under Items 7, 9 and 12, the Partnership's news release that announced the signing of a purchase and sale agreement to sell parts of the Partnership's crude oil pipeline and associated gathering and marketing operations and the signing of a non-binding letter of intent to purchase a volumetric production payment from Denbury. 50 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on the 29th day of March, 2004. GENESIS ENERGY, L.P. (A Delaware Limited Partnership) By: GENESIS ENERGY, INC., as General Partner By: /s/ Mark J. Gorman ------------------------------------- Mark J. Gorman Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. /s/ MARK J. GORMAN Director, Chief Executive Officer March 29, 2004 ---------------------------- and President Mark J. Gorman (Principal Executive Officer) /s/ ROSS A. BENAVIDES Chief Financial Officer, March 29, 2004 ---------------------------- General Counsel and Secretary Ross A. Benavides (Principal Financial Officer) /s/ KAREN N. PAPE Vice President and Controller March 29, 2004 ---------------------------- (Principal Accounting Officer) Karen N. Pape Chairman of the Board and March __, 2004 ---------------------------- Director Gareth Roberts /s/ RONALD T. EVANS Director March 29, 2004 ---------------------------- Ronald T. Evans /s/ HERBERT I GOODMAN Director March 29, 2004 ---------------------------- Herbert I. Goodman /s/ SUSAN O. RHENEY Director March 29, 2004 ---------------------------- Susan O. Rheney /s/ PHIL RYKHOEK Director March 29, 2004 ---------------------------- Phil Rykhoek /s/ J. CONLEY STONE Director March 29, 2004 ---------------------------- J. Conley Stone /s/ MARK A. WORTHEY Director March 29, 2004 ---------------------------- Mark A. Worthey 51 GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page ---- Independent Auditors' Report .............................................. 53 Consolidated Balance Sheets, December 31, 2003 and 2002 ................... 54 Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 55 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 56 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 57 Consolidated Statements of Partners' Capital for the Years Ended December 31, 2003, 2002 and 2001 ....................................... 58 Notes to Consolidated Financial Statements ................................ 59

52 INDEPENDENT AUDITORS' REPORT Genesis Energy, L.P. Houston, Texas We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P., (the "Partnership") as of December 31, 2003 and 2002, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 2 and 4 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill and discontinued operations. As discussed in Note 17 to the consolidated financial statements, in 2001, the Partnership changed its method of accounting for derivative financial instruments. /s/ Deloitte & Touche LLP ------------------------- DELOITTE & TOUCHE LLP Houston, Texas March 19, 2004 53 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands)

December 31, December 31, 2003 2002 ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents ................................... $ 2,869 $ 1,071 Accounts receivable - trade ................................. 66,732 80,664 Inventories ................................................. 1,546 4,952 Insurance receivable ........................................ 15,524 3,425 Other ....................................................... 1,540 1,985 --------- --------- Total current assets ..................................... 88,211 92,830 FIXED ASSETS, at cost .......................................... 70,695 118,418 Less: Accumulated depreciation ............................. (36,724) (73,958) --------- --------- Net fixed assets ......................................... 33,971 44,460 CO2 ASSETS, net of amortization ................................ 24,073 -- OTHER ASSETS, net of amortization .............................. 860 980 --------- --------- TOTAL ASSETS ................................................... $ 147,115 $ 137,537 ========= ========= LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable - Trade .................................................... $ 60,108 $ 82,640 Related party ............................................ 7,067 4,746 Accrued liabilities ......................................... 20,069 8,834 --------- --------- Total current liabilities ................................ 87,244 96,220 LONG-TERM DEBT ................................................. 7,000 5,500 COMMITMENTS AND CONTINGENCIES (Note 18) MINORITY INTERESTS ............................................. 517 515 PARTNERS' CAPITAL Common unitholders, 9,314 and 8,625 units issued and outstanding, respectively .................................. 51,299 34,626 General partner ............................................. 1,055 715 Accumulated other comprehensive loss ........................ -- (39) --------- --------- Total partners' capital .................................. 52,354 35,302 --------- --------- TOTAL LIABILITIES AND PARTNERS' CAPITAL ........................ $ 147,115 $ 137,537 ========= =========

The accompanying notes are an integral part of these consolidated financial statements. 54 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts)

Year Ended December 31, --------------------------------------------- 2003 2002 2001 ----------- ----------- ----------- REVENUES: Crude oil gathering and marketing: Unrelated parties .......................................... $ 641,684 $ 636,107 $ 2,971,785 Related parties ............................................ -- 3,036 29,847 Crude oil pipeline ............................................ 15,134 13,485 9,948 CO2 revenues .................................................. 1,079 -- -- ----------- ----------- ----------- Total revenues .......................................... 657,897 652,628 3,011,580 COSTS AND EXPENSES: Crude oil costs: Unrelated parties .......................................... 562,626 589,598 2,943,935 Related parties ............................................ 59,653 26,452 36,699 Field operating ............................................ 11,497 11,916 11,270 Crude oil pipeline operating costs ............................ 10,026 8,076 7,038 CO2 transportation costs - related party ...................... 355 -- -- General and administrative .................................... 8,768 7,864 11,307 Depreciation and amortization ................................. 4,641 4,603 5,340 Impairment of long-lived assets ............................... -- -- 9,589 Change in fair value of derivatives ........................... -- 1,279 (1,681) Net gain on disposal of surplus assets ........................ (236) (705) (167) Other operating charges ....................................... -- 1,500 1,500 ----------- ----------- ----------- Total costs and expenses ................................ 657,330 650,583 3,024,830 ----------- ----------- ----------- OPERATING INCOME (LOSS) .......................................... 567 2,045 (13,250) OTHER INCOME (EXPENSE): Interest income ............................................... 34 69 166 Interest expense .............................................. (1,020) (1,104) (693) ----------- ----------- ----------- Income (loss) from continuing operations before minority interests and cumulative effect of change in accounting principle ....................................... (419) 1,010 (13,777) Minority interests in continuing operations ...................... -- -- (1) ----------- ----------- ----------- INCOME (LOSS) FROM CONTINUING OPERATIONS ......................... (419) 1,010 (13,776) Discontinued operations: Income from operations from discontinued Texas System (including gain on disposal of $13,028) before minority interests ..................................... 13,742 4,082 (30,306) Minority interests in discontinued operations .................... 1 -- (3) ----------- ----------- ----------- INCOME FROM DISCONTINUED OPERATIONS .............................. 13,741 4,082 (30,303) CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF MINORITY INTEREST EFFECT ...................................... -- -- 467 ----------- ----------- ----------- NET INCOME (LOSS) ................................................ $ 13,322 $ 5,092 $ (43,612) =========== =========== ===========

55 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED (In thousands, except per unit amounts)

Year Ended December 31, -------------------------------------------- 2003 2002 2001 --------- --------- --------- NET INCOME PER COMMON UNIT- BASIC AND DILUTED: Income (loss) from continuing operations before cumulative effect of change in accounting principle ............................ $ (0.05) $ 0.11 $ (1.57) Income from discontinued operations ................ 1.55 0.47 (3.44) Cumulative effect of change in accounting principle ....................................... -- -- 0.05 --------- --------- --------- NET INCOME (LOSS) .................................. $ 1.50 $ 0.58 $ (4.96) ========= ========= ========= Weighted average number of common units outstanding ........................................... 8,715 8,625 8,624 ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands)

Year Ended December 31, ----------------------------------------- 2003 2002 2001 -------- -------- -------- NET INCOME (LOSS) ......................................................... $ 13,322 $ 5,092 $(43,612) OTHER COMPREHENSIVE INCOME (LOSS): Change in fair value of derivatives used for hedging purposes ........ 39 (39) -- -------- -------- -------- COMPREHENSIVE INCOME (LOSS) ............................................... $ 13,361 $ 5,053 $(43,612) ======== ======== ========

The accompanying notes are an integral part of these consolidated financial statements. 56 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)

Year Ended December 31, --------------------------------------- 2003 2002 2001 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ............................................... $ 13,322 $ 5,092 $ (43,612) Adjustments to reconcile net income to net cash provided by operating activities - Depreciation ................................................. 5,970 4,965 6,228 Amortization of CO2 contracts and covenant not-to-compete .... 534 848 1,318 Amortization and write-off of credit facility issuance costs . 1,031 736 23 Impairment of long-lived assets .............................. -- -- 45,061 Cumulative effect of change in accounting principle .......... -- -- (467) Change in fair value of derivatives .......................... 39 2,055 (2,259) Gain on disposal of assets ................................... (13,264) (708) (167) Minority interests equity in earnings (losses) ............... 1 -- (4) Other non-cash charges ....................................... 228 1,500 1,605 Changes in components of working capital - Accounts receivable ....................................... 13,932 81,134 167,666 Inventories ............................................... 3,758 (1,051) (2,743) Other current assets ...................................... (11,654) 3,909 4,854 Accounts payable .......................................... (20,211) (86,159) (154,117) Accrued liabilities ....................................... 11,007 (4,904) (5,230) --------- --------- --------- Net cash provided by operating activities ......................... 4,693 7,417 18,156 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment ............................. (4,910) (4,211) (1,882) CO2 contracts acquisition ....................................... (24,401) -- -- Change in other assets .......................................... (24) 5 -- Proceeds from disposal of assets ................................ 22,341 2,243 453 --------- --------- --------- Net cash used in investing activities ............................. (6,994) (1,963) (1,429) CASH FLOWS FROM FINANCING ACTIVITIES: Bank borrowings (repayments), net ............................... 1,500 (8,400) (8,100) Credit facility issuance fees ................................... (1,093) -- (1,312) Issuance of limited and general partner interests ............... 5,012 -- -- Minority interests contributions ................................ 1 -- -- Distributions to common unitholders ............................. (1,294) (1,725) (6,898) Distributions to General Partner ................................ (27) (35) (141) Distributions to minority interest owner ........................ -- -- (1) Purchase of treasury units, net ................................. -- -- (6) --------- --------- --------- Net cash provided by (used in) financing activities ............... 4,099 (10,160) (16,458) Net increase (decrease) in cash and cash equivalents .............. 1,798 (4,706) 269 Cash and cash equivalents at beginning of period .................. 1,071 5,777 5,508 --------- --------- --------- Cash and cash equivalents at end of period ........................ $ 2,869 $ 1,071 $ 5,777 ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. 57 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In thousands)

Partners' Capital ------------------------------------------------------------------------------- Accumulated Number of Other Common Common General Treasury Comprehensive Units Unitholders Partner Units Income Total --------- ----------- ------- -------- ------------- ----- Partners' capital, January 1, 2001 .......... 8,625 $ 80,960 $ 1,661 $ (6) $ -- $ 82,615 Net loss .................................... -- (42,740) (872) -- -- (43,612) Cash distributions .......................... -- (6,898) (141) -- -- (7,039) Purchase of treasury units .................. -- -- -- (6) -- (6) Issuance of treasury units to Restricted Unit Plan participants ........ -- -- -- 12 -- 12 Excess of expense over cost of treasury units issued for Restricted Unit Plan ................................ -- 39 -- -- -- 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2001 ........ 8,625 31,361 648 -- -- 32,009 Net income .................................. -- 4,990 102 -- -- 5,092 Cash distributions .......................... -- (1,725) (35) -- -- (1,760) Change in fair value of derivatives used for hedging purposes ................ -- -- -- -- (39) 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2002 ........ 8,625 34,626 715 -- (39) 35,302 Net income .................................. -- 13,055 267 -- -- 13,322 Cash distributions .......................... -- (1,294) (27) -- -- (1,321) Issuance of units ........................... 689 4,912 100 -- -- 5,012 Change in fair value of derivatives used for hedging purposes ................ -- -- -- -- 39 39 ----- -------- -------- -------- -------- -------- Partners' capital, December 31, 2003 ........ 9,313 $ 51,299 $ 1,055 $ -- $ -- $ 52,354 ===== ======== ======== ======== ======== ========

The accompanying notes are an integral part of these consolidated financial statements. 58 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Organization Genesis Energy, L.P. ("GELP" or the "Partnership") is a publicly traded Delaware limited partnership engaged in gathering, marketing and transportation of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed in December 1996 through an initial public offering of 8.6 million Common Units, representing limited partner interests in GELP of 98%. The General Partner of GELP is Genesis Energy, Inc. (the "General Partner") which owns a 2% general partner interest in GELP. The General Partner is owned by Denbury Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. In November 2003, an additional 0.7 million Common Units were sold to our general partner in a private placement. These Common Units are not registered with the Securities and Exchange Commission. See Note 7. Genesis Crude Oil, L.P. is the operating limited partnership and is owned 99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to as GCOLP. Basis of Presentation The accompanying financial statements and related notes present the consolidated financial position as of December 31, 2003 and 2002 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 2003, 2002 and 2001, and changes in comprehensive income for the years ended December 31, 2003, 2002 and 2001. All significant intercompany transactions have been eliminated. Certain reclassifications were made to prior period amounts to conform to current period presentation. Such reclassifications had no effect on reported net income, total assets, total liabilities or partners' equity. No provision for income taxes related to the operation of GELP is included in the accompanying consolidated financial statements; as such income will be taxable directly to the partners holding partnership interests in the Partnership. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates that we make include: (1) estimated useful lives of assets, which impacts depreciation and amortization, (2) accruals related to revenues and expenses, (3) liability and contingency accruals, (4) estimated fair value of assets and liabilities acquired, and (5) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred. While we believe these estimates reasonable, actual results could differ from these estimates. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Partnership has no requirement for compensating balances or restrictions on cash. 59 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Inventories Crude oil inventories held for sale are valued at the lower of average cost or market. Fuel inventories are carried at the lower of cost or market. Fixed Assets Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 15 years for pipelines and related assets, 3 to 7 years for vehicles and transportation equipment, and 3 to 10 years for buildings, office equipment, furniture and fixtures and other equipment. Long-lived assets are reviewed for impairment. In 2001, we recorded a charge for impairment of our pipeline assets as we did not believe the recorded values of the assets could be recovered through future cash flows. On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." Under SFAS No. 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows. Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil volumes are carried at their weighted average cost. We account for asset retirement obligations in accordance with SFAS 143. SFAS 143 requires that the cost for asset retirement obligations be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense systematically as with depreciation. With respect to our pipelines, federal regulations will require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon termination of the lease term, however the lease terms are continuous until a party to the lease gives notice that it wishes the lease to terminate. However the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates. In the third quarter of 2003, we recorded a liability in the amount of $0.7 million representing the anticipated cost to remove a pipeline from offshore waters of the State of Louisiana. The costs are expected to be incurred before June 30, 2004. CO2 and Other Assets Other assets consist primarily of CO2 assets and intangibles. The CO2 assets include a volumetric production payment and long-term contracts to sell the CO2 volume. The contract value is being amortized on a units-of-production method. See Note 5. Intangibles included a covenant not to compete, which was amortized over five years ending during 2003, and credit facility fees which are being amortized over the period the facility is in effect. Minority Interests Minority interests represent a 0.01% general partner interest in GCOLP held by the General Partner. Environmental Liabilities We provide for the estimated costs of environmental contingencies when liabilities are likely to occur and reasonable estimates can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred. 60 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Revenue Recognition Revenues from gathering and marketing of crude oil are recognized when title to the crude oil is transferred to the customer. Revenues from transportation of crude oil by our pipelines are recognized upon delivery of the barrels to the location designated by the shipper. Pipeline loss allowance revenues are recognized to the extent that pipeline loss allowances charged to shippers exceed pipeline measurement losses for the period based upon the fair market value of the crude oil upon which the allowance is based. Revenues from CO2 activities are recorded when title transfers to the customer at the inlet meter of the customer's facility. Cost of Sales Crude oil cost of sales consists of the cost of crude oil and field and pipeline operating expenses. Field and pipeline operating expenses consist primarily of labor costs for drivers and pipeline field personnel, truck rental costs, fuel and maintenance, utilities, insurance and property taxes. Cost of sales for the CO2 activities consists of a transportation fee charged by Denbury (currently $0.16 per Mcf) to transport the CO2 to the customer through Denbury's pipeline. Derivative Instruments and Hedging Activities We minimize our exposure to price risk by limiting our inventory positions, therefore we rarely need to use derivative instruments. In 2003, we used derivative instruments only once. However should we use derivative instruments to hedge exposure to price risk, we would account for those derivative transactions in accordance with Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded on the balance sheet as assets and liabilities based on the derivative's fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, the derivative's gains and losses offset related results on the hedged item in the income statement. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. If a derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements and is accounted for using traditional accrual accounting. Net Income Per Common Unit Basic and diluted net income per Common Unit is calculated on the weighted average number of outstanding Common Units, after exclusion of the 2 percent General Partner interest from net income. The weighted average number of Common Units outstanding was 8,714,845, 8,624,554 and 8,623,741 for the years ended December 31, 2003, 2002 and 2001, respectively. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. See Note 7 for a computation of net income per Common Unit. Recent Accounting Pronouncements We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See Fixed Assets above. The FASB issued SFAS No. 145, "Rescission of FASB Statements 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This statement revised accounting guidance related to the extinguishment of debt and accounting for certain lease transactions. It also amended other accounting literature to clarify its meaning, applicability and to make various technical corrections. Our adoption of this standard effective January 1, 2003 had no impact on our financial statements. On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the 61 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS date of commitment to an exit plan. This adoption of this statement had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 for information regarding this sale. We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements. We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements. On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows. 62 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. INVENTORIES Inventories consisted of the following (in thousands).

December 31, ------------------------------ 2003 2002 ------------ ------------ Crude oil inventories, at lower of cost or market................ $ 1,476 $ 4,841 Fuel and supplies inventories, at lower of cost or market........ 70 111 ------------ ------------ Total inventories.......................................... $ 1,546 $ 4,952 ============ ============

4. FIXED ASSETS Fixed assets consisted of the following (in thousands).

December 31, ------------------------------ 2003 2002 ------------ ------------ Land and buildings............................................... $ 1,481 $ 3,492 Pipelines and related assets..................................... 57,429 101,397 Vehicles and transportation equipment............................ 1,510 1,527 Office equipment, furniture and fixtures......................... 3,043 3,138 Other ........................................................... 7,232 8,864 ------------ ------------ 70,695 118,418 Less - Accumulated depreciation.................................. (36,724) (73,958) ------------- ------------ Net fixed assets................................................. $ 33,971 $ 44,460 ============ ============

Depreciation expense, including discontinued operations, was $5,970,000, $4,965,000 and $6,228,000 for the years ended December 31, 2003, 2002, and 2001, respectively. In 2001, the Partnership recorded an impairment charge related to its pipeline assets of $38,049,000. See Note 9. 5. CO2 AND OTHER ASSETS Carbon Dioxide (CO2) Assets We purchased the CO2 assets from Denbury for $24.4 million in cash in November 2003. These assets included the assignment of an interest in 167.5 billion cubic feet (Bcf) of CO2, under a volumetric production payment and Denbury's existing long-term CO2 supply agreements with three of its industrial customers. The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012 and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary adjustments, from us for those transportation services. The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The three industrial contracts extend through 2010, 2012 and 2015. The CO2 assets are being amortized on a units-of-production method. After purchase price adjustments, we had 164.9 Bcf of CO2 at acquisition, and the $24.4 million cost is being amortized based on the volume of CO2 sold each month. For the two months in 2003 when we owned the CO2 assets, we recorded amortization of $328,000. Based on the historical deliveries of CO2 to the customers (which have exceeded minimum take-or-pay volumes), we would expect that amortization for the next five years to be approximately $2,147,000 annually. 63 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Assets Other assets consisted of the following (in thousands).

December 31, ------------------------------ 2003 2002 ------------ ------------ Credit facility fees........................................ $ 1,117 $ 1,312 Covenant not to compete..................................... $ -- $ 4,238 Other....................................................... 40 42 ------------ ------------ 1,157 5,592 Less - Accumulated amortization............................. (297) (4,612) ------------- ------------ Net other assets............................................ $ 860 $ 980 ============ ============

In 2001, the Partnership recorded an impairment charge related to goodwill of $7,012,000, which reduced the net book value of goodwill to zero at December 31, 2001. See Note 11. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," which we adopted January 1, 2002, we test other intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. As of December 31, 2003, no impairment has occurred of our remaining intangible assets. Amortization expense for goodwill was $470,000 for the year ended December 31, 2001. Amortization expense for the covenant-not-to-compete was $205,000 for the year ended December 31, 2003 and $848,000 for the each of the years ended December 31, 2002 and 2001. Accumulated amortization of the covenant-not-to-compete was $4,033,000 at December 31, 2002. The covenant-not-to-compete was fully amortized and expired in 2003. Amortization expense for the credit facility fees for the year ended December 31, 2003 was $298,000. Additionally in 2003, we charged to expense $733,000 of fees related to the facility that existed at the end of 2002. In 2002 and 2001, we recorded $456,000 and $23,000 of amortization of credit facility fees, respectively. 6. DEBT In March 2003, the Partnership entered into $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit. The key terms of the Fleet Facility are as follows: - Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%. - The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%. - We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%. - The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. - Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets. - The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum 64 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders. Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under Note 7. At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. We were in compliance with the Fleet Facility covenants at December 31, 2003. 7. PARTNERS' CAPITAL AND DISTRIBUTIONS Partners' Capital During 2001, 2002 and the first ten months of 2003, partnership equity consisted of the general partner interest of 2% and 8.6 million Common Units representing limited partner interests of 98%. The Common Units were sold to the public in an initial public offering in December 1996. In November 2003, we issued 688,811 Common Units to our General Partner in exchange for $4,925,000. We received $101,000 from the general partner for its proportionate capital contribution. At December 31, 2003, a total of 9,313,811 Common Units were outstanding. The general partner interest is held by our General Partner. The Partnership is managed by the General Partner. The General Partner also holds a 0.01% general partner interest in GCOLP, which is reflected as a minority interest in the consolidated balance sheet at December 31, 2003. The Partnership Agreement authorizes the General Partner to cause GCOLP to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other GCOLP needs. Distributions Generally, we will distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 million in total), which was paid in February 2004. Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the quarterly distribution, measured once each month, in order for us to make a distribution for the quarter. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003. 65 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net Income Per Common Unit The following table sets forth the computation of basic net income per Common Unit for 2003, 2002, and 2001 (in thousands, except per unit amounts).

Year Ended December 31, -------------------------------------- 2003 2002 2001 -------- -------- -------- Numerators for basic and diluted net income per common unit: Income (loss) from continuing operations ............... $ (419) $ 1,010 $(13,776) Less general partner 2% ownership ...................... (8) 20 (275) -------- -------- -------- Income (loss) from continuing operations available for common unitholders .................... $ (411) $ 990 $(13,501) ======== ======== ======== Income (loss) from discontinued operations ............. $ 13,741 $ 4,082 $(30,306) Less general partner 2% ownership ...................... 275 82 (606) -------- -------- -------- Income (loss) from continuing operations available for common unitholders .................... $ 13,466 $ 4,000 $(29,700) ======== ======== ======== Cumulative effect of change in accounting principle ........................................... $ -- $ -- $ 467 -------- -------- -------- Less general partner 2% ownership ...................... -- -- 9 -------- -------- -------- Cumulative effect of change in accounting principle available for common unitholders .......... $ -- $ -- $ 458 ======== ======== ======== Denominator for basic and diluted per Common Unit - weighted average number of Common Units outstanding .... 8,715 8,625 8,623 ======== ======== ======== Basic and diluted net income (loss) per Common Unit: Income (loss) from continuing operations ............... $ (0.05) $ 0.11 $ (1.57) Income (loss) from discontinued operations ............. 1.55 0.47 (3.44) Cumulative effect of change in accounting principle .... -- -- 0.05 -------- -------- -------- Net income (loss) ...................................... $ 1.50 $ 0.58 $ (4.96) ======== ======== ========

8. BUSINESS SEGMENT INFORMATION Our operations consist of three operating segments: (1) Crude Oil Gathering and Marketing - the purchase and sale of crude oil at various points along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate and intrastate crude oil pipeline transportation; and (2) CO2 marketing - the sale of CO2 acquired under a volumetric production payment to industrial customers. Prior to 2003, we managed our crude oil gathering, marketing and pipeline operations as a single segment. The tables below reflect all periods presented as though the current segment designations had existed, and include only continuing operations data. We evaluate segment performance based on segment margin before depreciation and amortization. All of our revenues are derived from, and all of our assets are located in the United States. 66 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Crude Oil ---------------------------- Gathering and CO2 Marketing Pipeline Marketing Total --------- -------- --------- ----- (in thousands) Year Ended December 31, 2003 Revenues: External Customers ............................................. $ 641,684 $ 11,799 $ 1,079 $ 654,562 Intersegment (a) ............................................... -- 3,335 -- 3,335 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $ 641,684 $ 15,134 $ 1,079 $ 657,897 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 7,908 5,108 $ 724 $ 13,740 Capital expenditures ........................................... $ 635 $ 2,302 $ 24,401 $ 27,338 Maintenance capital expenditures ............................... $ 635 $ 2,226 $ -- $ 2,861 Net fixed and other long-term assets ........................... $ 5,480 $ 29,351 $ 24,073 $ 58,904 Year Ended December 31, 2002 Revenues: External Customers ............................................. $ 639,143 $ 10,214 $ -- $ 649,357 Intersegment (a) ............................................... -- 3,271 -- 3,271 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $ 639,143 $ 13,485 $ -- $ 652,628 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 11,177 5,409 $ -- $ 16,586 Capital expenditures ........................................... $ 690 $ 1,981 $ -- $ 2,671 Maintenance capital expenditures ............................... $ 690 $ 1,981 $ -- $ 2,671 Year Ended December 31, 2001 Revenues: External Customers ............................................. $3,001,632 $ 7,809 $ -- $ 654,017 Intersegment (a) ............................................... -- 2,139 -- 2,139 ---------- ---------- ---------- ---------- Total revenues of reportable segments .......................... $3,001,632 $ 9,948 $ -- $3,011,580 ========== ========== ========== ========== Segment margin excluding depreciation and amortization (b) ..... $ 9,728 2,910 $ -- $ 12,638 Capital expenditures ........................................... $ 388 $ 615 $ -- $ 1,003 Maintenance capital expenditures ............................... $ 388 $ 615 $ -- $ 1,003

(a) Intersegment sales were conducted on an arm's length basis. (b) Segment margin was calculated as revenues less cost of sales and operations expense. A reconciliation of segment margin to income from continuing operations for each year presented is as follows: 67 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, ---------------------------------- 2003 2002 2001 -------- -------- -------- (in thousands) Segment margin excluding depreciation and amortization ........................................ $ 13,740 $ 16,586 $ 12,638 General and administrative expenses ..................... 8,768 7,864 11,307 Depreciation, amortization and impairment ............... 4,641 4,603 14,929 Change in fair value of derivatives ..................... -- 1,279 (1,681) Net gain on disposal of surplus assets .................. (236) (705) (167) Interest expense, net ................................... 986 1,035 527 Other operating charges ................................. -- 1,500 1,500 Minority interests in continuing operations ............. -- -- (1) -------- -------- -------- Income from continuing operations ....................... $ (419) $ 1,010 $(13,776) ======== ======== ========

9. IMPAIRMENT OF PIPELINE ASSETS In the fourth quarter of 2001, as a result of declining revenues and rising costs from its pipeline operations for operations and maintenance combined with regulatory changes requiring additional testing for pipeline integrity, the Partnership determined that the estimated undiscounted future cash flows did not support the carrying value of its pipelines. Under Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121) (the relevant accounting guidance at that time), the carrying value of the assets must be reduced to the fair value of the assets. The estimated fair value of the pipelines was determined by reducing the estimated undiscounted future cash flows plus salvage value to its present value at December 31, 2001. Because the goodwill on the consolidated balance sheet was generated from the acquisition of the pipeline assets, the carrying value of the net goodwill was reduced to zero with the remaining impairment allocated to the fixed assets. An impairment charge totaling $45.1 million was recorded for the pipeline assets and goodwill. $9.6 million of this impairment charge related to continuing operations, with the remaining $35.5 million included in discontinued operations. 10. OTHER OPERATING CHARGES In each of the third quarter of 2002 and the fourth quarter of 2001, the Partnership recorded a charge of $1.5 million, for a total of $3.0 million, related to environmental matters from the Mississippi spill that occurred in 1999. These charges are reflected as other operating charges on the consolidated statement of operations for 2002 and 2001. 11. DISCONTINUED OPERATIONS In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc., which plans to convert the segments to natural gas service. Some remaining segments not sold to these parties were abandoned in place. The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce cost or risk of operation. We determined we should consider selling these assets due to potential risks to the continuation of our revenue stream that may result from consolidation of pipeline assets in the area and projections of maintenance capital costs that may occur. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks. TEPPCO paid us $21.6 million for the assets it acquired. TEPPCO also assumed the responsibilities for unpaid royalties related to the crude oil purchase and sale contracts it assumed and we transferred $0.6 million to TEPPCO for those liabilities. We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us 68 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period. We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to October 31, 2003, subject to certain conditions. TEPPCO will pay the first $25,000 for any environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of these amounts up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO will cease in ten years. During 2003, we recorded $0.4 million in termination benefits related to the sale to TEPPCO. These benefits included retention bonuses and severance pay for employees affected by the sale. Under the terms of the sale to Blackhawk, we received no consideration from Blackhawk for the sale and agreed to provide transition services through March 31, 2004. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years. The assets we abandoned had been idle since 2002 or earlier. The net book value of these assets was charged to impairment expense in 2001. Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:

Year Ended December 31, ---------------------------------------- 2003 2002 2001 --------- --------- --------- (in thousands) Revenues: Gathering and marketing ........................................ $ 263,930 $ 252,452 $ 324,371 Pipeline ....................................................... 6,480 6,726 4,247 --------- --------- --------- Total revenues .............................................. 270,410 259,178 328,618 Costs and expenses: Crude costs .................................................... 256,986 243,262 313,202 Field operating costs .......................................... 4,718 4,535 4,379 Pipeline operating costs ....................................... 5,846 4,852 3,859 General and administrative ..................................... 282 425 384 Depreciation and amortization .................................. 1,864 1,210 2,206 Change in fair value of derivatives ............................ -- 815 (578) Net gain on disposal of surplus assets ......................... -- (3) -- Impairment of long-lived assets ................................ -- -- 35,472 --------- --------- --------- Total costs and expenses .................................... 269,696 255,096 358,924 --------- --------- --------- Operating income from discontinued operations ..................... 714 4,082 (30,306) Gain on disposal of assets ........................................ 13,028 -- -- --------- --------- --------- Income from operations from discontinued Texas System before minority interests ............................... $ 13,742 $ 4,082 $ (30,306) ========= ========= =========

12. TRANSACTIONS WITH RELATED PARTIES Except for below-market guaranty fees paid in 2001 and 2002 to Salomon Smith Barney Holdings Inc. ("Salomon"), sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than those conducted with unaffiliated parties. Salomon was the owner of the General Partner until May 2002. 69 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Sales and Purchases of Crude Oil Denbury became a related party in May 2002. Purchases of crude oil from Denbury for the year ended December 31, 2003, were $59.7 million. Purchases from Denbury during the year ended December 31, 2002, while it was a related party (May to December) were $26.5 million and purchases during the period before it became an affiliate were $10.9 million. Purchases from Denbury are partially secured by letters of credit. Genesis and Salomon ceased to be related parties in May 2002. During the period in 2002 when Salomon was a related party, sales totaling $3.0 million were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases and sales of $36.7 million and $29.8 million, respectively, were made in 2001 with Phibro. These transactions were bulk and exchange transactions. General and Administrative Services We do not directly employ any persons to manage or operate our business. Those functions are provided by the General Partner. We reimburse the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by us were $16,028,000, $17,280,000, and $18,089,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Due to Related Parties At December 31, 2003 and 2002, we owed Denbury $6.9 million and $4.1 million, respectively, for purchases of crude oil. Additionally, we owed Denbury $0.1 million for CO2 transportation services at December 31, 2003. We owed the General Partner $0.1 million and $0.6 million at December 31, 2003 and 2002, respectively, for administrative services. Directors' Fees In 2003, we paid $120,000 to Denbury for the services of four of Denbury's officers who serve as directors of the General Partner, the same rate at which our independent directors were paid. CO2 Volumetric Production Payment and Transportation We acquired a volumetric production payment from Denbury in November 2003 for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2 for us to our customers. For November and December 2003, we paid Denbury $355,000 for these transportation services related to our sales of CO2. See Note 5. Financing Our general partner guarantees our obligations under the Fleet Facility. Our general partner that guarantees the obligations is a wholly-owned subsidiary of Denbury. The obligations are not guaranteed by Denbury or any of its other subsidiaries. Citicorp Credit Agreement In December 2001, Citicorp began providing us with a working capital and letter of credit facility. Citicorp and Salomon are both subsidiaries of Citicorp, Inc. From January 1, 2002, until May 14, 2002, when Citicorp ceased to be a related party, we incurred letter of credit fees, interest and commitment fees totaling $396,000 under the Credit Agreement. In December 2001, we paid Citicorp $900,000 as a fee for providing the facility. This facility fee was being amortized to earnings over the two-year life of the Credit Agreement and was included in interest expense on the consolidated statements of operations. When the facility was replaced in March 2003, the unamortized balance of this fee totaling $371,000 was charged to interest expense. In 2001, the Partnership paid Citicorp for interest and commitment fees totaling $27,000. Guaranty Fees In 2001, Salomon provided a guaranty facility to the Partnership and, from January 2002 to April 2002, Salomon provided guaranties under a transition arrangement with Salomon, Citicorp and the Partnership. For the years ended December 31, 2002 and 2001, the Partnership paid Salomon $61,000 and $1,250,000, respectively, for guarantee fees. The guarantee fees are included as a component in cost of crude on the consolidated statements of operations. These guarantee fees were less than the cost of a letter of credit facility from a bank. 70 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. SUPPLEMENTAL CASH FLOW INFORMATION Cash received by us for interest during the years ended December 31, 2003, 2002 and 2001 was $34,000, $68,000, and $195,000, respectively. Cash payments for interest were $1,194,000, $537,000, and $1,391,000 during the years ended December 31, 2003, 2002 and 2001, respectively. 14. EMPLOYEE BENEFIT PLANS We do not directly employ any of the persons responsible for managing or operating our activities. Employees of the General Partner provide those services and are covered by various retirement and other benefit plans. In order to encourage long-term savings and to provide additional funds for retirement to its employees, the General Partner sponsors a profit-sharing and retirement savings plan. Under this plan, the General Partner's matching contribution is calculated as an equal match of the first 3% of each employee's annual pretax contribution and 50% of the next 3% of each employee's annual pretax contribution. The General Partner also made a profit-sharing contribution of 3% of each eligible employee's total compensation. The expenses included in the consolidated statements of operations for costs relating to this plan were $507,000, $564,000, and $603,000 for the years ended December 31, 2003, 2002 and 2001, respectively. The General Partner also provided certain health care and survivor benefits for its active employees. In 2003, 2002 and 2001, these benefit programs were self-insured, with a catastrophic insurance policy to limit our costs. The General Partner plans to continue self-insuring these plans in the future. The expenses included in the consolidated statements of operations for these benefits were $1,368,000, $1,360,000, and $1,526,000 in 2003, 2002 and 2001, respectively. Stock Appreciation Rights Plan In December 2003, the Board approved a Stock Appreciation Rights (SAR) plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit. The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated his employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below. Upon vesting, the participant may exercise his rights and receive a cash payment calculated as the difference between the average of the closing market price of our Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date. Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested. On December 31, 2003 awards of 423,057 rights were allocated to participants with a strike price of $9.26 per right. In 2003, we recorded non-cash expense of $228,000 for the increase between the strike price of the outstanding rights and the closing market price for Common Units on December 31, 2003. In 2001, we recorded expense of $55,000 related to a restricted unit plan that has been terminated. Bonus Plan In March 2003, the Compensation Committee of the Board of Directors of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the 71 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS financial performance of the Partnership by rewarding all employees for achieving financial performance objectives. The Bonus Plan will be administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash. Bonuses will be paid to employees after the end of the year, but only if distributions are made to the Common Unitholders. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and our General Partner can amend or change the Bonus Plan at any time. 15. MAJOR CUSTOMERS AND CREDIT RISK We derive our revenues from customers primarily in the crude oil industry. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of major international corporate entities with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil Company accounted for 22.5%, 15.4% and 11.0% of total revenues in 2003, respectively. Marathon Ashland Petroleum LLC and ExxonMobil Corporation accounted for 18.5% and 13.6% of total revenues in 2002, respectively. In 2001, BP Amoco Corporation subsidiaries and Enron Corporation subsidiaries accounted for 10.6% and 14.1% of total revenues, respectively. The majority of the revenues from these five customers in all three years relate to our gathering and marketing operations. 16. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities in the Consolidated Balance Sheets approximated fair value due to the short maturity of these instruments. Additionally, the carrying value of the long-term debt approximated fair value due to its floating rate of interest. 17. DERIVATIVES Our market risk in the purchase and sale of its crude oil contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps. Historically, any contracts we have used to hedge market risk were less than one year in duration. During 2003 we did not use any hedging instruments. We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil prices. On January 1, 2001, we adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", which established new accounting and reporting guidelines for derivative instruments and hedging activities. Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset 72 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We mark to fair value our derivative instruments at each period end with changes in fair value of derivatives not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. Unrealized gains or losses on derivative transaction qualifying as hedges are reflected in other comprehensive income. In general, SFAS No. 133 requires that at the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. On January 1, 2001, recognition of our derivatives resulted in a gain of $0.5 million, which was recognized in the consolidated statement of operations as the cumulative effect of adopting SFAS No. 133. Certain derivative contracts related to written option contracts had been recorded on the balance sheet at fair value at December 31, 2000, so no adjustment was necessary for those contracts upon adoption of SFAS No. 133. We regularly review our contracts to determine if the contracts qualify for treatment as derivatives. We had no contracts qualifying for treatment as derivatives at December 31, 2003. At December 31, 2002, we determined that the only contract qualifying as a derivative was a qualifying cash flow hedge. The decrease of $39,000 in the fair value of this hedge is recorded in other comprehensive income and as accumulated other comprehensive income in the consolidated balance sheet. No hedge ineffectiveness was recognized during 2002. The anticipated transaction (crude oil sales) occurred in January 2003, and all related amounts held in other comprehensive income at December 31, 2002, were reclassified to the consolidated statement of operations in the first quarter of 2003. We determined that all other derivative contracts qualified for the normal purchase and sale exemption at December 31, 2003 and 2002. The decrease in fair value of our net asset for derivatives not qualifying as hedges during 2002 was $2.1 million. The increase in fair value of our net asset for derivatives not qualifying as hedges during 2001 was $1.7 million. These changes in fair value are recorded in the consolidated statements of operations under the caption "Change in fair value of derivatives." 18 COMMITMENTS AND CONTINGENCIES Commitments and Guarantees We lease office space for our headquarters office under a long-term lease. The lease extends until October 31, 2005. We lease office space for a field office under a lease that expires in 2007. Ryder provides tractors and trailers to us under an operating lease that also includes full-service maintenance. Under the terms of the lease, we lease 46 tractors and 46 trailers. We pay a fixed monthly rental charge for each tractor and trailer and a fee based on mileage for the maintenance services. We have ordered an additional 5 tractors and trailers from Ryder that we expect to receive during the first quarter of 2004. We lease three tanks for use in our pipeline operations. The tank lease expires in 2004, however we have advised the lessor that we may want to extend the lease. Additionally, we lease a segment of pipeline. Under the terms of that lease, we make lease payments based on throughput, and we have no minimum volumetric or financial requirements remaining. We also lease service vehicles for our field personnel. 73 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The future minimum rental payments under all non-cancelable operating leases as of December 31, 2003, were as follows (in thousands).

Office Tractors and Service Space Trailers Tanks Vehicles Total ------ ------------ ------ -------- ------ 2004 ........................................ $ 489 $1,734 $ 465 $ 360 $3,048 2005 ........................................ 410 2,338 -- 204 2,952 2006 ........................................ 18 559 -- 10 587 2007 ........................................ 15 531 -- -- 546 2008 ........................................ -- 528 -- -- 528 2009 and thereafter ......................... -- 935 -- -- 935 ------ ------ ------ ------ ------ Total minimum lease obligations ............. $ 932 $6,625 $ 465 $ 574 $8,596 ====== ====== ====== ====== ======

Total operating lease expense was as follows (in thousands).

Year ended December 31, 2003............................. $ 4,736 Year ended December 31, 2002............................. $ 4,713 Year ended December 31, 2001............................. $ 4,379

We have guaranteed $3.3 million of residual value related to the leases of tractors and trailers. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote. GELP has guaranteed crude oil purchases of GCOLP. These guarantees, totaling $11.4 million, were provided to counterparties. To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated balance sheet. GELP, the General Partner and the subsidiaries of GCOLP have guaranteed the payments by GCOLP to Fleet under the terms of the Fleet Facility related to borrowings and letters of credit. Borrowings at December 31, 2003 were $7.0 million and are reflected in the consolidated balance sheet. To the extent liabilities exist under the letters of credit, such liabilities are included in the consolidated balance sheet. We have contractual commitments (forward contracts) arising in the ordinary course of our crude oil marketing activities. At December 31, 2003, the Partnership had commitments to purchase 1,854,000 barrels of crude oil in January 2004, and 986,000 barrels of crude oil between February 2004, and October 2004. We had commitments to sell 1,865,000 barrels of crude oil in January 2004, and 690,000 barrels of crude oil between February 2004 and June 2004. All of these contracts are associated with market-price-related contracts. The total commitment to purchase crude oil would be valued at $89.4 million, using market prices at December 31, 2003. The total commitment to sell crude oil would be valued at $82.0 million, using market prices at December 31, 2003. In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards and Securities and Exchange Commission (SEC) regulations. During 2004, we expect to spend between $0.5 million and $1.0 million related to compliance with the requirements of the Sarbanes Oxley Act of 2002 as required by the SEC. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will expend a total of approximately $2.2 million in 2004 and 2005 for testing and rehabilitation under regulations requiring assessment of the integrity of crude oil pipelines. Pennzoil Litigation We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurance carriers settled this litigation for $12.8 million. We have recorded in Accrued Liabilities on our consolidated statement of operations the obligation for this settlement, and in Insurance Receivable we have recorded the insurance reimbursement for this obligation. The settlement was funded in 74 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million was funded by us. We will receive reimbursement of the $6.9 million from the insurance company no later than May 2004. PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter. Environmental On December 20, 1999, we had a spill of crude oil from our Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek nearby. A portion of the oil then flowed into the Leaf River. The oil spill is covered by insurance and the direct financial impact to us of the cost of the clean-up has not been material. Included in insurance receivable on the consolidated balance sheet at December 31, 2003 is $2.8 million related to this spill. Management of the Partnership has reached an agreement in principle with the US Environmental Protection Agency and the Mississippi Department of Environmental Quality for the payment of fines under environmental laws with respect to this oil spill. Based on this agreement in principle, in 2001 and 2002, a total accrual of $3.0 million was recorded for these fines. The fines will not be covered by insurance. We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may substantially affect our business. Other Matters We have taken additional security measures since the terrorist attacks of September 11, 2001 in accordance with guidance provided by the Department of Transportation and other government agencies. We cannot assure you that these security measures would prevent our facilities from a concentrated attack. Any future attacks on us or our customers or competitors could have a material effect on our business, whether insured or not. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable. We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Such matters presently pending are not expected to have a material adverse effect on our financial position, results of operations or cash flows. 75 EXHIBIT INDEX Exhibits 3.1 Certificate of Limited Partnership of Genesis Energy, L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545) 3.2 Third Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31, 2002) 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996) 3.4 Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.1 to Form 8-K dated July 31, 2002) 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"), Howell Corporation ("Howell"), certain subsidiaries of Howell, Genesis, the Operating Partnership and Genesis Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for the year ended December 31, 1996) 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended December 31, 1996) 10.3 Office Lease at One Allen Center between Trizec Allen Center Limited Partnership (Landlord) and Genesis Crude Oil, L.P. (Tenant) (incorporated by reference to Exhibit 10 to Form 10-Q for the quarterly period ended September 30, 1997) 10.4 Credit Agreement dated as of March 14, 2003, between Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet National Bank and Certain Financial Institutions (incorporated by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2002) 10.5 Pipeline Sale and Purchase Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and Genesis Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K dated October 31, 2003) 10.6 Purchase and Sale Agreement between TEPPCO Crude Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K dated October 31, 2003) *10.7 Production Payment Purchase and Sale Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. executed November 14, 2003 *10.8 Carbon Dioxide Transportation Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P. *10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan. 11.1 Statement Regarding Computation of Per Share Earnings (See Notes 2 and 7 to the Consolidated Financial Statements) *21.1 Subsidiaries of the Registrant *31.1 Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *31.2 Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. *32.1 Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification by Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ---------- * Filed herewith + A management contract or compensation plan or arrangement.